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As filed with the Securities and Exchange Commission on May 7, 2012

Registration No. 333-179502

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

AMENDMENT NO. 1

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Diamondback Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware		1311		45-4502447
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

 

 

500 West Texas

Suite 1225

Midland, Texas 79701

(432) 221-7400

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

 

Teresa Dick

Chief Financial Officer

Diamondback Energy, Inc.

14301 Caliber Drive

Suite 300

Oklahoma City, Oklahoma 73134

(405) 463-6900

(Name, address, including zip code and telephone number, including area code, of agent for service)

 

 

Copies to:

Seth R. Molay, P.C. Akin Gump Strauss Hauer & Feld LLP 1700 Pacific Avenue, Suite 4100 Dallas, TX 75201 (214) 969-4780		J. Michael Chambers Keith Benson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, TX 77002 (713) 546-7416

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨				Accelerated filer		¨
Non-accelerated filer		x		(Do not check if a smaller reporting company)		Smaller reporting company		¨

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this prospectus is not complete and may be changed. We and the selling stockholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we and the selling stockholders are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED MAY 7, 2012.

PROSPECTUS

             Shares

 

Diamondback Energy, Inc.

Common Stock

 

 

We are selling              shares of common stock and the selling stockholders are selling              shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $         and $         per share. We have applied to list our common stock on The NASDAQ Global Market under the symbol “FANG.”

We and the selling stockholders granted the underwriters an option to purchase up to an aggregate of              additional shares of our common stock to cover the underwriters’ option to purchase additional shares.

We are an “emerging growth company” under applicable Securities and Exchange Commission rules and will be subject to reduced public company reporting requirements. Investing in our common stock involves risks. See “Risk Factors” beginning on page 14.

 

		Price to Public		Underwriting Discounts and Commissions		Proceeds to Diamondback		Proceeds to Selling Stockholders
Per Share		$		$		$		$
Total		$		$		$		$

Delivery of the shares of common stock will be made on or about                     , 2012.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

The date of this prospectus is                     , 2012.

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ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, and the selling stockholders and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We, the selling stockholders and the underwriters are only offering to sell, and only seeking offers to buy, our common stock in jurisdictions where offers and sales are permitted.

The information contained in this prospectus is accurate and complete only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock by us, the selling stockholders or the underwriters. Our business, financial condition, results of operations and prospects may have changed since that date.

Dealer Prospectus Delivery Obligation

Until                      (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their option to purchase additional shares.

 

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RISK FACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our business is difficult to evaluate because we have a limited operating history.

We were incorporated in Delaware on December 30, 2011. All of our historical oil and natural gas assets, operations and results described in this prospectus are currently those of Windsor Permian, which is an entity controlled by our equity sponsor, Wexford. Immediately prior to the closing of this offering, Windsor Permian will become our wholly-owned subsidiary and we will acquire the oil and gas assets of Gulfport located in the Permian Basin in the Gulfport contribution. The oil and natural gas properties of Windsor Permian, Gulfport and Windsor UT described in this prospectus have been acquired by Windsor Permian, Gulfport and Windsor UT since December 2007. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Approximately 74% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Approximately 74% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2011, our total capital expenditures, including expenditures for leasehold interest and property acquisitions, drilling, seismic and infrastructure, were approximately $81.7 million. Our 2012 capital budget for drilling, completion and infrastructure, including investments in water

 

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disposal infrastructure and gathering line projects, is estimated to be approximately $180.0 million. To date, we have financed capital expenditures primarily with funding from our equity sponsor, borrowings under our revolving credit facility and cash generated by operations.

In the near term, we intend to finance our capital expenditures with cash flow from operations, proceeds from this offering and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

•

our proved reserves;

 

•

the volume of oil and natural gas we are able to produce from existing wells;

 

•

the prices at which oil and natural gas are sold; and

 

•

our ability to acquire, locate and produce new reserves.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2012 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through March 31, 2012, after giving effect to the Contributions, we drilled a total of 147 gross wells and participated in an additional 11 gross non-operated wells, of which 149 wells were completed as producing wells and nine wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.

 

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Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. Only 329 of these identified potential vertical drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs and drilling results. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre downspacing will produce at the same rates as those on 40-acre spacing. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of March 31, 2012 after giving effect to the Contributions, we had leases representing 250 net acres expiring in 2012, 222 net acres expiring in 2013, 2,041 net acres expiring in 2014 and 13,628 net acres expiring in 2015. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

•

the domestic and foreign supply of oil and natural gas;

 

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the level of prices and expectations about future prices of oil and natural gas;

 

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the level of global oil and natural gas exploration and production;

 

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the cost of exploring for, developing, producing and delivering oil and natural gas;

 

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the price of foreign imports;

 

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political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

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speculative trading in crude oil and natural gas derivative contracts;

 

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the level of consumer product demand;

 

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weather conditions and other natural disasters;

 

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risks associated with operating drilling rigs;

 

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technological advances affecting energy consumption;

 

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domestic and foreign governmental regulations and taxes;

 

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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

 

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proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

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the price and availability of alternative fuels; and

 

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overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. During 2011, prices ranged from $75.67 to $113.93 per Bbl for oil and wellhead natural gas market prices ranged from $2.79 to $4.92 per Mcf. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.02 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

We have entered into price swap derivatives and may in the future enter into forward sale contracts or additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. For the purpose of locking-in the value of a swap, we enter into counter-swaps from time to time. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we placed a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. Locking in the value of our swaps with counter-swaps, without entering into new swaps, exposes us to commodity price risks on the originally swapped position. As of December 31, 2010 and 2009, all of our swap contracts were locked-in with counter swaps. In October 2011, we placed a swap contract covering 1,000 Bbls per day of crude oil for the period from January 1, 2012 through December 31, 2013 at a price of $78.50 per barrel in 2012 and $80.55 per barrel in 2013. Such contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $12.7 million at December 31, 2011) and receivables from purchasers of our oil and natural gas production (approximately $5.0 million at December 31, 2011). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would

 

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significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $25.40, $17.78 and $11.21 for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2011, 2010 and 2009 was $15.2 million, $7.4 million and $3.2 million, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2011, 2010 and 2009. We may experience additional ceiling test write downs in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties” beginning of page 71 of this prospectus for a more detailed description of our method of accounting.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations are based on reports prepared by Ryder Scott as of December 31, 2011 and by Pinnacle as of December 31, 2010 and 2009, each an independent petroleum engineering firm. The estimates of proved reserves and related valuations attributable to the Windsor UT properties and the properties subject to the Gulfport contribution are based, in each case, on reports prepared by Ryder Scott as of December 31, 2011. Ryder Scott and Pinnacle, as applicable, conducted a well-by-well review of all our properties for the periods covered by their respective reserve reports using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas we ultimately recover being different from our reserve estimates.

The estimates of reserves as of December 31, 2011, 2010 and 2009 included in this prospectus were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2011, 2010 and 2009, respectively, in accordance with the revised SEC guidelines applicable to reserves estimates for such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

 

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The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 76% of our total estimated proved reserves at December 31, 2011 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, at December 31, 2011, all of our proved reserves were attributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

 

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We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. In addition, we intend to increase the number of rigs we have operating in 2012 and 2013. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining

 

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business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

We have incurred losses from operations during certain periods since our inception and may do so in the future.

We incurred a net loss of $0.5 million for the year ended December 31, 2011. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced, would adversely affect our financial condition and results of operations.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See “Business—Regulation—Environmental Matters and Regulation” and “Business—Regulation—Other Regulation of the Oil and Natural Gas Industry” beginning on pages 92 and 96, respectively, of this prospectus for a description of the laws and regulations that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the Environmental Protection Agency, or EPA, has commenced a study of the potential environmental impacts of

 

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hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act.

On April 17, 2012, EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds , or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95 percent reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014.

These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states, including Texas, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict

 

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hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the

 

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resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the of the percentage depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

 

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The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some

 

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studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC’s jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our new executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

A significant reduction by Wexford of its ownership interest in us could adversely affect us.

Prior to the Gulfport contribution, Wexford will beneficially own 100% of our equity interests. Upon completion of this offering, Wexford will beneficially own approximately     % of our common stock, or     % if the underwriters exercise in full their option to purchase additional shares. See “Principal and Selling Stockholders” beginning on page 122 of this prospectus. Further, we anticipate that several individuals who will serve as our directors upon completion of this offering will be affiliates of Wexford. We believe that Wexford’s substantial ownership interest in us provides Wexford with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities by or on behalf of DB Holdings following the completion of this offering, Wexford will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford sells all or a substantial portion of its ownership interest in us, Wexford may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. We also receive certain services, including drilling services from entities controlled by Wexford. These service contracts may generally be terminated on 30-days notice. In the event Wexford ceases to own a significant ownership interest in us, such services may not be available to us on terms acceptable to us, if at all.

 

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Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

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unusual or unexpected geological formations;

 

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loss of drilling fluid circulation;

 

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title problems;

 

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facility or equipment malfunctions;

 

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unexpected operational events;

 

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shortages or delivery delays of equipment and services;

 

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compliance with environmental and other governmental requirements; and

 

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adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical

 

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additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with the terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically

 

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dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to

 

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discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as early as December 31, 2013. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify for an exemption from the requirement to provide auditors’ attestation on internal controls afforded to emerging growth companies under the “Jumpstart Our Business Startups Act” enacted by the U.S. Congress in April 2012. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue

 

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acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We recorded compensation expense in 2011 and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, we recorded $0.5 million of compensation expense in 2011. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and anticipated stock-based incentive plans. These additional expenses will adversely affect our net income. We cannot determine the actual amount of these new stock-related compensation and benefit expenses at this time because applicable accounting practices generally require that they be based on the fair market value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

Our level of indebtedness may increase and reduce our financial flexibility.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

 

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a significant portion of our cash flows could be used to service our indebtedness;

 

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a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

•

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

 

•

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

 

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our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

•

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

 

•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

 

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Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility contains restrictive covenants that limit our ability to, among other things:

 

•

incur additional indebtedness;

 

•

create additional liens;

 

•

sell assets;

 

•

merge or consolidate with another entity;

 

•

pay dividends or make other distributions;

 

•

engage in transactions with affiliates; and

 

•

enter into certain swap agreements.

In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of our revolving credit facility, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our revolving credit facility, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our revolving credit facility, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our revolving credit facility or obtain needed waivers on satisfactory terms.

Our borrowings under our revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2011, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 3.3%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Under our revolving credit facility, which currently provides for a $100.0 million borrowing base, we are subject to semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves. Our revolving credit facility currently provides that the borrowing base will remain at $100.0 million through October 15, 2012, at which time the borrowing base will be reduced to $85.0 million, subject to the periodic and elective borrowing base redeterminations discussed above, and without consideration of the impact of the Gulfport contribution and the Windsor UT properties. Any significant reduction in our borrowing

 

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base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to this Offering and Our Common Stock

Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, Wexford and Gulfport will beneficially own approximately     % and     %, respectively, of our common stock, or     % and     %, respectively, if the underwriters exercise their option to purchase additional shares in full. See “Principal and Selling Stockholders” beginning on page 122 of this prospectus. In addition, individuals affiliated with Wexford and Gulfport serve on our Board of Directors, and Gulfport has the right to designate one individual as a nominee for election to our Board of Directors so long as it continues to beneficially own more than 10% of our outstanding common stock. As a result, Wexford and Gulfport, together, will be able to control, and Wexford alone will continue to be able to exercise significant influence over, matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford and Gulfport with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless Wexford approves the acquisition.

Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.

Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. If we choose to take advantage of any or all of these exemptions, our stockholders may not have the protections that these rules are intended to provide.

 

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The corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor, or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

•

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

 

•

permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

•

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described under the caption “Related Party Transactions” beginning on page 118 of this prospectus, these include, among others, drilling services provided to us to Bison Drilling and Field Services, LLC, real property leased by us from Fasken Midland, LLC and certain administrative services provided to us by Everest Operations Management LLC. Each of these entites is either controlled by or affiliated with Wexford, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexford may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “—Risks Related to this Offering and our Common Stock – Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders” on page 35 of this prospectus.

We will incur increased costs as a result of being a public company, which may significantly affect our financial condition.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

However, for as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, we intend to take advantage of certain exemptions from various reporting

 

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requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.”

We will remain an “emerging growth company” for up to five years, although if the market value of our common stock that is held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an “emerging growth company” as of the following December 31.

After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to the Oil and Natural Gas Industry and Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected” on page 32 of this prospectus.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart our Business Startups Act of 2012, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

There has been no public market for our common stock and if the price of our common stock fluctuates significantly, your investment could lose value.

Prior to this offering, there has been no public market for our common stock. Although we have applied to have our common stock listed on The NASDAQ Global Market, we cannot assure you that an active public market will develop for our common stock or that our common stock will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for our common stock does not develop, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the trading price for our common stock after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

 

•

our quarterly or annual operating results;

 

•

changes in our earnings estimates;

 

•

investment recommendations by securities analysts following our business or our industry;

 

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•

additions or departures of key personnel;

 

•

changes in the business, earnings estimates or market perceptions of our competitors;

 

•

our failure to achieve operating results consistent with securities analysts’ projections;

 

•

changes in industry, general market or economic conditions; and

 

•

announcements of legislative or regulatory change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. See “Shares Eligible for Future Sale” on page 127 of this prospectus. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have              shares of common stock outstanding, excluding stock options. All of the shares sold in this offering, except for any shares purchased by our affiliates, will be freely tradable.

DB Holdings, Gulfport and our directors and executive officers will be subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares of our common stock for a period of at least 180 days after the date of this prospectus, which period may be extended under limited circumstances, without the prior written approval of Credit Suisse Securities (USA) LLC. However, these lock-up agreements are subject to certain specific exceptions, including transfers of common stock as a bona fide gift or by will or intestate succession and transfers to such person’s immediate family or to a trust or to an entity controlled by such holder, provided that the recipient of the shares agrees to be bound by the same restrictions on sales. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of stock options granted to certain of our executive officers under their respective employment agreements.

The initial public offering price is substantially higher than the pro forma net tangible book value per share of our outstanding common stock. As a result, you will experience immediate and substantial dilution of

 

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approximately $         per share, representing the difference between our net tangible book value per share as of          after giving effect to this offering and an assumed initial public offering price of $         (which is the midpoint of the range set forth on the cover of the prospectus). A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) our net tangible book value per share after giving effect to this offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offered expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. See “Dilution” beginning on page 44 of this prospectus for a description of dilution.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

 

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provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;

 

•

limitations on the ability of our stockholders to call a special meeting and act by written consent;

 

•

the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;

 

•

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;

 

•

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and

 

•

the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.

These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

 

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We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

•

business strategy;

 

•

exploration and development drilling prospects, inventories, projects and programs;

 

•

oil and natural gas reserves;

 

•

identified drilling locations;

 

•

ability to obtain permits and governmental approvals;

 

•

technology;

 

•

financial strategy;

 

•

realized oil and natural gas prices;

 

•

production;

 

•

lease operating expenses, general and administrative costs and finding and development costs;

 

•

future operating results; and

 

•

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” beginning on pages 1, 14, 54 and 77, respectively, and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

Our net proceeds from the sale of              shares of common stock in this offering, assuming a public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $         million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds would be $         million if the underwriters’ option to purchase additional shares is exercised in full. At the closing of this offering, we intend to use approximately $         million of the net proceeds to repay outstanding borrowings under our revolving credit facility and $63.6 million to repay the Gulfport contribution note and, thereafter, we intend to use the balance of the proceeds from this offering to fund a portion of our exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions, working capital and the settlement of crude oil swaps. Upon repayment of the outstanding borrowings under our revolving credit facility, we will have $         million of borrowing capacity under that facility to further fund our exploration and development activities and for general corporate purposes.

All borrowings under our revolving credit facility are due and payable on October 14, 2014. As of April 30, 2012, $100.0 million was outstanding under our revolving credit facility and bore interest at a weighted average rate of 3.3% per annum. The amounts initially borrowed under our revolving credit facility were used to repay in full the outstanding indebtedness under our prior credit facility and for general corporate purposes. The Gulfport contribution note, which will be issued immediately prior to the closing of this offering in connection with the Gulfport contribution, does not bear interest and is due upon completion of this offering.

We will not receive any proceeds from the sale of shares by the selling stockholders, including any sale the selling stockholders may make upon exercise of the underwriters’ option to purchase additional shares.

An increase or decrease in the initial public offering price of $1.00 per share would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $             million. If our net proceeds are reduced, we will have less proceeds to fund our exploration and development activities and may not have sufficient funds to repay our revolving credit facility in full. Any reduction in net proceeds may cause us to need to borrow additional funds under our revolving credit facility to fund our operations, which would increase our interest expense and decrease our net income.

DIVIDEND POLICY

We have never declared or paid any cash dividends on our capital stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends in the foreseeable future. Any future determination as to the declaration and payment of dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. In addition, the terms of our revolving credit facility restrict the payment of dividends to the holders of our common stock and any other equity holders.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2011:

 

•

on an actual basis;

 

•

on a pro forma basis to give effect to the issuance of (a)              shares of our common stock to an affiliate of Wexford in exchange for its contribution to us of all the outstanding equity interests in Windsor Permian, (b)              shares of our common stock and the Gulfport contribution note to Gulfport in connection with the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie; and

 

•

on a pro forma basis described above as adjusted to give effect to the sale of shares of our common stock in this offering at an assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $ million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses and the use of a portion of those proceeds to repay outstanding borrowings as described under the caption “Use of Proceeds” on page 42 of this prospectus.

You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 54 and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 

		As of December 31, 2011
		Actual(1)				Pro Forma				Pro Forma As  Adjusted(2)
		(in thousands)
Cash and cash equivalents		$	6,802			$				$
Long term debt (including current maturities)(3)		$	85,000			$				$
Member’s equity			114,847				—				—
Stockholders’ equity:
Common stock, par value $0.01; 100 shares authorized and              shares issued and outstanding actual;              shares authorized and              shares issued and outstanding as adjusted for the offering			—
Additional paid-in capital			—
Accumulated deficit(4)			—
Total stockholders’ equity
Total capitalization		$	199,847			$				$

 

(1)

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the completion of the offering. The data in this table has been derived from the historical consolidated financial statements and other financial information included in this prospectus which pertain to the assets, liabilities, revenues and expenses of Windsor Permian LLC. Immediately prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary.

(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) would increase (decrease) each of cash and cash equivalents, additional paid-in-capital and total capitalization by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3)	At April 30, 2012, long term debt was $100.0 million.

(4)

Upon completion of this offering, we will recognize deferred tax liabilities and assets for temporary differences between the historical cost basis and tax basis of these assets and liabilities. Based on estimates of those temporary differences as of December 31, 2011, a net deferred tax liability of approximately $26.2 million will be recognized with a corresponding charge to earnings.

 

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DILUTION

Our reported net tangible book value as of December 31, 2011 was $         million, or $         per share, based upon shares outstanding as of that date after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. Net tangible book value per share is determined by dividing such number of outstanding shares of common stock into our net tangible book value, which is our total tangible assets less total liabilities. Assuming the sale by us of              shares of common stock offered in this offering at an estimated initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our net tangible book value as of December 31, 2011 would have been approximately $         million, or $         per share, after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) to the Gulfport contribution and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. This represents an immediate increase in net tangible book value of $         per share to our existing stockholders and an immediate dilution of $         per share to new investors purchasing shares at the initial public offering price.

The following table illustrates the per share dilution:

 

Assumed initial public offering price per share						$
Pro forma net tangible book value per share as of December 31, 2011		$
Increase per share attributable to new investors		$
As adjusted net tangible book value per share after the offering						$
Dilution per share to new investors						$

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth in the cover of this prospectus) would increase (decrease) our net tangible book value after the offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of December 31, 2011, after giving pro forma effect to the contribution to us by DB Holdings of all of the outstanding equity interests in Windsor Permian and to the Contributions, the number of shares of common stock to be issued by us to DB Holdings and Gulfport, which will be our existing stockholders immediately prior to this offering, and by the new investors at the assumed initial public offering price of $         per share, together with the total consideration paid and average price per share paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

 

		Shares Purchased						Total Consideration								Average Price
		Number		Percent				Amount				Percent				Per Share
Existing stockholders						%		$						%		$
New investors						%								%
Total					100.0	%		$					100.0	%		$

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to             , or approximately     % of the total number of shares of common stock.

The data in the table excludes              shares of common stock reserved for issuance under our equity incentive plan.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following selected historical consolidated financial data as of December 31, 2011 and 2010 and for each of the years in the three-year period ended December 31, 2011 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated balance sheet data as of December 31, 2009 and 2008 and the selected historical consolidated financial data for 2008 and the period from inception on October 23, 2007 to December 31, 2007 are derived from our audited financial statements not included in this prospectus. The balance sheet data as of December 31, 2007 is derived from our unaudited financial statements not included in this prospectus. The unaudited pro forma data presented gives effect to income taxes assuming that the Company operated as a taxable corporation throughout the periods presented. Operating results for the periods ended December 31, 2011, 2010, 2009, 2008 and 2007 are not necessarily indicative of results that may be expected for any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 54 and our historical consolidated financial statements and related notes included elsewhere in this prospectus.

 

		Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2011				2010				2009				2008
Statement of Operations Data:
Oil and natural gas revenues		$	47,180,802			$	26,441,927			$	12,716,011			$	18,238,692			$	578,336
Other income			1,490,910				811,247				—				—				—
Expenses:
Lease operating expense			10,345,355				4,588,559				2,366,623				3,375,419				25,684
Production taxes			2,333,853				1,346,879				663,068				1,008,991				136,077
Gathering and transportation			201,828				105,870				42,091				53,407				2,637
Oil and natural gas services			1,732,892				811,247				—				—				—
Depreciation, depletion and amortization			15,402,826				8,145,143				3,215,891				10,199,581				138,066
Impairment of oil and gas properties			—				—				—				83,164,230				—
General and administrative			3,603,479				3,051,627				5,062,618				5,459,874				6,609
Asset retirement obligation accretion expense			63,259				37,856				27,934				23,569				514
Total expenses			33,683,492				18,087,181				11,378,225				103,285,071				309,587
Income (loss) from operations			14,988,220				9,165,993				1,337,786				(85,046,379	)			268,749
Other income (expense):
Interest income			11,197				34,474				35,075				625,086				23,581
Interest expense			(2,528,058	)			(836,265	)			(10,938	)			—				—
Loss on derivative contracts			(13,009,393	)			(147,983	)			(4,068,005	)			(9,528,220	)			(4,791,587	)
Loss from equity investment			(7,017	)			—				—				—				—
Total other expense, net			(15,533,271	)			(949,774	)			(4,043,868	)			(8,903,134	)			(4,768,006	)
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro Forma C Corporation Data:(1)(2)
Historical net income (loss) before income taxes		$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro forma for income taxes, net of valuation allowance			—				—				—				—				—
Pro forma net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro forma income (loss) per common share — basic and diluted		$
Weighted average pro forma shares outstanding — basic and diluted

 

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		Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2011				2010				2009				2008
Selected Cash Flow and Other Financial Data:
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Depreciation, depletion and amortization			15,905,315				8,145,143				3,215,891				10,199,581				138,066
Other non-cash items			13,844,010				344,461				4,108,464				92,716,019				4,792,101
Change in operating assets and liabilities			1,179,920				(11,529,999	)			(1,916,707	)			3,076,317				(2,448,557	)
Net cash provided by (used in) operating activities		$	30,384,194			$	5,175,824			$	2,701,566			$	12,042,404			$	(2,017,647	)
Net cash used in investing activities		$	(76,314,042	)		$	(53,134,641	)		$	(32,149,617	)		$	(84,196,562	)		$	(86,863,149	)
Net cash provided by financing activities		$	48,642,492			$	49,618,254			$	23,849,250			$	80,182,600			$	88,881,463
		As of December 31,
		2011				2010				2009				2008				2007
Balance sheet data:
Cash and cash equivalents		$	6,802,389			$	4,089,745			$	2,430,308			$	8,029,109			$	667
Other current assets			24,130,450				20,947,659				2,263,097				1,389,810				2,489,231
Oil and gas properties, net — using full cost method of accounting			206,342,604				135,782,510				89,777,517				73,786,284				83,375,502
Well equipment to be used in development of oil and gas properties			—				—				5,413,310				8,503,178				—
Other property and equipment, net			684,015				11,059,220				105,564				161,103				—
Other assets			11,524,427				637,562				82,813				—				—
Total assets		$	249,483,885			$	172,516,696			$	100,072,609			$	91,869,484			$	85,865,400
Current liabilities		$	42,418,305			$	20,010,276			$	13,972,080			$	18,011,452			$	126,757
Note payable credit facility-long term			85,000,000				44,766,687				—				—				—
Derivative contracts-long term			6,138,573				1,373,864				1,416,431				2,868,452				1,141,587
Asset retirement obligations			1,079,725				727,826				481,887				374,287				214,850
Members’ equity			114,847,282				105,638,043				84,202,211				70,615,293				84,382,206
Total liabilities and members’ equity		$	249,483,885			$	172,516,696			$	100,072,609			$	91,869,484			$	85,865,400
		Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2011				2010				2009				2008
Other financial data:
Adjusted EBITDA(3)		$	31,505,264			$	17,383,466			$	4,616,686			$	8,966,087			$	430,910

 

(1)

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical consolidated financial statements and other financial information included in this prospectus pertain to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Windsor Permian LLC was treated as a partnership for federal income tax purposes. As a result, essentially all of Windsor Permian LLC’s taxable earnings and losses were passed through to Wexford, and Windsor Permian LLC did not pay federal income taxes at the entity level. Prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian LLC will become subject to federal income tax. For comparative purposes, we have included pro forma financial data to give effect to income taxes net of valuation allowance assuming the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation in all periods presented in the accompanying table. If the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation during the periods presented herein, we would have incurred net operating losses in each period presented. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A

 

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valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each of the above periods of zero. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.

(2)

Unaudited pro forma basic and diluted income (loss) per share will be presented for the latest fiscal year on the basis of the aggregate number of shares to be issued to Gulfport in connection with the Gulfport contribution and to DB Holdings in connection with its contribution to us of all of the outstanding equity interests in Windsor Permian LLC to us, upon determination of the number of those shares.

(3)

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before loss on derivative contracts, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity based compensation and asset retirement obligation accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our credit facility.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

 

		Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2011				2010				2009				2008
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Loss on derivative contracts			13,009,393				147,983				4,068,005				9,528,220				4,791,587
Interest expense			2,528,058				836,265				10,938				—				—
Depreciation, depletion and amortization			15,905,315				8,145,143				3,215,891				10,199,581				138,066
Impairment of oil and gas properties			—				—				—				83,164,230				—
Equity-based compensation expense			544,290				—				—				—				—
Asset retirement obligation accretion expense			63,259				37,856				27,934				23,569				514
Adjusted EBITDA		$	31,505,264			$	17,383,466			$	4,616,686			$	8,966,087			$	430,910

 

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Financial Statements

Introduction

The following unaudited pro forma condensed consolidated financial statements and related notes of the Company have been prepared to show the effect of the Contributions and the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. The unaudited pro forma condensed consolidated financial statements should be read together with the historical financial statements of Windsor Permian and Windsor UT and the historical Statements of Revenues and Direct Operating Expenses of certain property interests of Gulfport Energy Corporation included in this prospectus. The accompanying unaudited pro forma condensed consolidated financial statements are based on assumptions and include adjustments as explained in the accompanying notes. The acquisition of certain property interests of Gulfport Energy Corporation (the Gulfport properties) will be treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets recognized at fair value on the date of transfer. The Windsor UT contribution is treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer. The pro forma data presented reflect events directly attributable to the Contributions and other described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods.

The unaudited pro forma condensed consolidated balance sheet assumes that the Contributions and other described transactions occurred on December 31, 2011. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 assumes that the Contributions and other described transactions occurred on January 1, 2011.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheets

December 31, 2011

 

		Windsor Permian Historical				Windsor UT Historical				Pro Forma Adjustments				Pro Forma
Assets
Cash and cash equivalents		$	6,802,389			$	156,733			$				$
Other current assets			24,130,450				214,633
Total current assets			30,932,839				371,366
Oil and natural gas properties, net using full cost method of accounting			206,342,604				14,122,632					(a)
Other property and equipment			684,015				—
Other assets			11,524,427				—					(b)
Total assets		$	249,483,885			$	14,493,998
Liabilities and Members’ Equity
Current liabilities		$	42,418,305			$	280,383					(a)
Note payable credit facility-long term			85,000,000				—
Derivative contracts-long term			6,138,573				—
Asset retirement obligations			1,079,725				24,267					(c)
Members’ equity			114,847,282				14,189,348					(a)(c)
Total liabilities and members’ equity		$	249,483,885			$	14,493,998			$				$

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Year ended December 31, 2011

 

		Windsor Permian Historical				Gulfport Contribution Historical				Windsor UT Historical				Pro Forma Adjustments				Pro Forma
Revenues:
Oil and natural gas revenues		$	47,180,802			$	23,052,000			$	694,666			$				$
Oil and natural gas services			1,490,910				—				—				(b	)
Total revenues			48,671,712				23,052,000				694,666
Costs and expenses:
Lease operating expenses			10,345,355				5,484,000				251,824
Production taxes			2,333,853				1,276,000				32,016
Gathering and transportation			201,828				—				—
Oil and natural gas services			1,732,892				—				—					(b)
Depreciation, depletion and amortization			15,402,826				—				198,712					(d)
General and administrative expenses			3,603,479				—				37,044
Asset retirement obligation accretion expense			63,259				—				1,255					(c)
Total costs and expenses			33,683,492				6,760,000				520,851
Income from operations			14,988,220				16,292,000				173,815
Other income (expense)
Interest income			11,197				—				—
Interest expense			(2,528,058	)			—				—
Loss on derivative contracts			(13,009,393	)			—				—
Loss from equity investment			(7,017	)			—				—
Total other expense, net			(15,533,271	)			—				—
Net income (loss)		$	(545,051	)		$	16,292,000			$	173,815			$				$

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Diamondback Energy, Inc

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

1. Basis of Presentation

The historical financial information is derived from the historical financial statements of Windsor Permian and Windsor UT and the historical statements of revenues and direct operating expenses of certain property interests of Gulfport. The unaudited pro forma condensed consolidated balance sheet as of December 31, 2011 has been prepared as if the Contributions and other described transactions had taken place on December 31, 2011. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 assumes that the Contributions and other described transactions had occurred on January 1, 2011.

2. Pro Forma Assumptions and Adjustments

We made the following adjustments in the preparation of the unaudited pro forma condensed consolidated financial statements.

 

(a)

To record the contribution of the Gulfport properties at fair value for              shares of our common stock, which will represent 35% of our outstanding common stock immediately prior to the closing of this offering, and $63,590,050 in the form of a non-interest bearing promissory note that will be repaid in full upon the closing of this offering. The allocation of the purchase price to the assets acquired is preliminary and, therefore, subject to change.

 

(b)	To record the distribution of minority equity interests in Bison and Muskie to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us.

 

(c)	To record incremental accretion of discount on asset retirement obligation associated with the Contributions.

 

(d)	To record incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the Contributions, amortized on a unit-of-production basis over the remaining life of total proved reserves, as applicable.

3. Oil and Natural Gas Producing Activities

The following table presents estimated unaudited pro forma volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2011 and changes in proved reserves during the year, assuming continuation of economic conditions prevailing at the end of the year. The weighted average prices at December 31, 2011 used for reserve report purposes are $93.09 per Bbl of oil, $56.62 per Bbl of natural gas liquids and $3.96 per Mcf of natural gas, respectively.

The Company emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

 

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		Year Ended December 31, 2011
		Windsor Permian Historical												Gulfport Contribution Historical												Windsor UT Historical												Total Pro Forma
		Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2011			18,819				5,564				21,662				9,358				3,107				11,926				811				269				1,033				28,988				8,940				34,621
Extensions, discoveries and other additions			1,706				448				1,824				764				217				992				94				18				60				2,564				683				2,876
Revisions of prior reserve estimates			(3,366	)			(1,162	)			(3,454	)			(1,828	)			(474	)			(599	)			487				(1	)			(160	)			(4,707	)			(1,637	)			(4,213	)
Production			(442	)			(87	)			(413	)			(208	)			(59	)			(273	)			(8	)			—				—				(658	)			(146	)			(686	)
As of December 31, 2011			16,717				4,763				19,619				8,086				2,791				12,046				1,384				286				933				26,187				7,840				32,598
Proved Developed Reserves:
January 1, 2011			3,308				1,105				4,255				1,840				794				3,048				64				21				82				5,212				1,920				7,385
December 31, 2011			3,805				1,233				5,187				2,097				706				3,050				144				30				99				6,046				1,969				8,336
Proved Undeveloped Reserves:
January 1, 2011			15,511				4,459				17,407				7,518				2,313				8,878				747				248				951				23,776				7,020				27,236
December 31, 2011			12,912				3,530				14,432				5,989				2,085				8,996				1,240				256				834				20,141				5,871				24,262

 

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Diamondback Energy, Inc

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

The following pro forma standardized measure of discounted estimated future net cash flows and changes therein relating to the combined proved oil and natural gas reserves of Windsor Permian and the Contributions as of and for the year ended December 31, 2011 were made in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

 

		Year Ended December 31, 2011
		Windsor Permian Historical				Gulfport Contribution Historical				Windsor UT Historical				Total Pro Forma
Future cash flows		$	1,901,127,669			$	960,918,000			$	148,561,297			$	3,010,606,966
Future development costs			(373,750,257	)			(236,336,000	)			(36,600,000	)			(646,686,257	)
Future production costs			(458,939,218	)			(166,899,000	)			(38,872,203	)			(664,710,421	)
Future production taxes			(97,457,261	)			(50,235,000	)			(7,410,909	)			(155,103,170	)
Future net cash flows			970,980,933				507,448,000				65,678,185				1,544,107,118
10% discount to reflect timing of cash flows			(627,533,692	)			(305,160,000	)			(47,669,824	)			(980,363,516	)
Standardized measure of discounted future net cash flows		$	343,447,241			$	202,288,000			$	18,008,361			$	563,743,602

The primary changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2011:

 

		Year Ended December 31, 2011
		Windsor Permian Historical				Gulfport Contribution Historical				Windsor UT Historical				Total Pro Forma
Sales and transfers of oil and gas produced, net of production costs		$	(34,299,766	)		$	(16,292,000	)		$	(410,826	)		$	(51,002,592	)
Net changes in prices and production costs and development costs			86,655,407				48,089,000				383,765				135,128,172
Extension and discoveries			69,375,680				29,432,000				4,195,434				103,003,114
Revisions of previous quantity estimates, less related production costs			(100,433,225	)			(71,088,000	)			1,899,993				(169,621,232	)
Accretion of discount			33,035,782				16,211,000				864,314				50,111,096
Change in production rates and other			(41,244,457	)			33,830,000				2,432,541				(4,981,916	)
Total change in standardized measure of discounted future net cash flows		$	13,089,421			$	40,182,000			$	9,365,221			$	62,636,642

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the combined financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this prospectus.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Permian Basin in West Texas. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. For the year ended December 31, 2011, our production was approximately 74% oil, 15% natural gas liquids and 11% natural gas.

We began operations in December 2007 with our acquisition of certain strategic oil and gas properties located in the Permian Basin of West Texas from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers for approximately $85.0 million. Through this transaction, we acquired 4,174 net acres with production at the time of acquisition of approximately 800 net barrels of oil equivalent, or BOE/d, from 33 gross (16.5 net) wells. Subsequently, we acquired approximately 25,851 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 30,025 net acres at March 31, 2012 and, after giving effect to the Contributions, we had 49,703 net acres in the Permian Basin. Since our initial acquisition in the Permian Basin through March 31, 2012, we drilled or participated in the drilling of 152 gross (81 net) wells (or 158 gross (141 net) wells after giving effect to the Contributions) on our acreage in this area, primarily targeting the Wolfberry play. We are the operator of approximately 99% of our Permian Basin acreage.

We have increased our initial leasehold position through the following acquisitions in the Wolfberry play for an aggregate net cost of $41.2 million.

 

•

In 2008, we acquired 6,247 net acres at the Spanish Trail and Munn prospects in Midland County, Texas through 11 leases and one mineral deed, with 5,146 net acres attributable to one lease;

 

•

Commencing in 2008 and ending in 2010, we acquired leases at the Barron prospect in Midland County, Texas covering 225 net acres;

 

•

Commencing in 2008 and ending in 2011, we acquired leases at the Gist prospect in Ector County, Texas covering 1,404 net acres;

 

•

In 2008, 2009 and 2011, we acquired 35 leases at the UL prospect in Andrews and Upton Counties, Texas covering a total of 9,966 net acres;

 

•

Beginning in 2008, we acquired 17 leases at the Hurt/WHL prospect in Ector County, Texas covering 2,779 net acres;

 

•

In 2009, we acquired one lease at the Cumberland prospect located in Midland County, Texas covering 207 net acres;

 

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•

In 2010, we acquired leases at the North Howard prospect located in Howard County, Texas that currently cover 176 net acres;

 

•

In 2010, we acquired 912 net acres at the Sabo prospect in Upton County, Texas;

 

•

In 2010 and 2011, we acquired 150 leases at the Big Max prospect located in Andrews County, Texas covering 825 net acres; and

 

•

In 2011, we acquired three leases in the Clete prospect in Crockett County, Texas covering 3,110 net acres.

Diamondback Energy, Inc. was incorporated in Delaware on December 30, 2011 as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical financial information included in this prospectus pertains to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Prior to the closing of this offering, Wexford will cause DB Holdings, an entity controlled by Wexford, to contribute all of the outstanding equity interests in Windsor Permian LLC to us in exchange for shares of our common stock, and Windsor Permian LLC will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. Contemporaneously with the contribution of Windsor Permian to us, Gulfport will complete the Gulfport contribution in exchange for shares of our common stock.

Prior to Windsor Permian being contributed to us, Windsor Permian will distribute to its sole member its minority equity interests in Bison Drilling and Field Services LLC, or Bison, and Muskie Holdings LLC, or Muskie. Bison was formed in November 2010 as a wholly-owned subsidiary of Windsor Permian. Between March 2011 and April 2012, Gulfport and various entities controlled by Wexford acquired interests in Bison, which reduced Windsor Permian’s interest to approximately 22%. Bison owns and operates four drilling rigs and various oil and natural gas well servicing equipment and has performed drilling and field services for us. Muskie was formed in October 2011 when Windsor Permian contributed certain assets, real estate and rights in a lease covering land in Wisconsin to Muskie in exchange for a 48.6% equity interest. The contributed lease is prospective for oil and natural gas fracture grade sand. At the time of the contribution, the remaining interests in Muskie were held by Gulfport and entities controlled by Wexford. Through additional contributions from the Wexford-controlled entities, Windsor Permian’s equity interest in Muskie decreased to approximately 33%. Windsor Permian’s interests in Bison and Muskie will be distributed to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us so we may focus our activities on our oil and natural gas exploration and development activities. We recorded revenues attributable to Bison in our consolidated statements of operations of $0.8 million during 2010 and $1.5 million during the first quarter of 2011, at which time Bison was deconsolidated for financial reporting purposes. Muskie was formed in 2011, and we recorded a loss from equity method investments of $7,107 million for 2011. The interests in Bison and Muskie are reflected in “Investments-equity method” on our consolidated balance sheets. For additional information regarding Bison and Muskie, see “Unaudited Pro Forma Condensed Consolidated Financial Statements” and “Related Party Transactions” beginning on pages 48 and 118, respectively, of this prospectus and Note 5 to our consolidated financial statements appearing elsewhere in this prospectus.

Since we began operations, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our

 

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ability to continue to add reserves in excess of production. We will maintain our focus on managing costs associated with drilling and the development and production of reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. We expect the permitting and approval process to become more difficult with increased activism from environmental and other groups which may extend the time it takes us to receive permits. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Reserves and pricing

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. Among other changes, the final rule requires us to report oil and natural gas reserves and calculate the full cost ceiling value using the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ending in the reporting period. The prior SEC rule required using prices at period end. The requirements of this standard became effective for the year ended December 31, 2009. These revisions and requirements affect the comparability between reporting periods prior to and after the year ended December 31, 2009 for reserve volume and value estimates, full cost pool write-down calculations and the calculations of depletion of oil and gas assets.

In the table below, Ryder Scott estimated all of our proved reserves at December 31, 2011 and Pinnacle estimated all of our proved reserves at December 31, 2010 and 2009. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

		2011				2010				2009
Estimated Net Proved Reserves:
Oil (Bbls)			16,716,867				18,819,050				29,230,940
Natural gas (Mcf)			19,618,865				21,662,720				27,481,820
Natural gas liquids (Bbls)			4,763,274				5,563,978				7,522,225
Total (BOE)			24,749,952				27,993,481				41,333,468

 

		2011				2010				2009
		Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (Bbls)		$	93.09			$	77.61			$	58.84
Natural gas (Mcf)		$	3.91			$	4.14			$	3.64
Natural gas liquids (Bbls)		$	56.33			$	40.74			$	29.37

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and gas reserves.

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the year ended December 31, 2011, our revenues were derived 84% from oil sales,

 

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10% from natural gas liquids sales, 3% from natural gas sales and 3% from oil and natural gas services. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per Bbl in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $15.52 per MMBtu in January 2006. During 2011, West Texas Intermediate prices ranged from $75.67 to $113.93 per Bbl for oil and wellhead natural gas market prices ranged from $2.79 to $4.92 per Mcf. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.02 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time-to-time we enter into derivative arrangements for our crude oil and natural gas production. We utilize commodity derivatives to reduce our exposure to fluctuations in NYMEX WTI benchmark prices. While these derivative contracts stabilize our cash flows when market prices are below our contract prices, they also prevent us from realizing increases in our cash flow when market prices are higher than our contract prices. We will sustain realized and unrealized losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain realized and unrealized gains to the extent our derivatives contract prices are higher than market prices. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as other income (expense) in our statements of operations.

Principal components of our cost structure

Lease operating and natural gas transportation and treating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to other fixed assets.

Impairment expense. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.

Other income (expense)

Interest income. This represents the interest received on our cash and cash equivalents.

 

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Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these commodity derivative instruments.

Loss from equity investment. This line item represents our proportionate share of the earnings and losses from our investment in the membership interests of Muskie, an equity method investment.

Income tax expense. As of December 31, 2011, we were a limited liability company treated as a disregarded entity for federal income tax purposes. Accordingly, no provision for federal or state corporate income taxes has been provided for the year ended December 31, 2011 or prior fiscal years because taxable income is allocated directly to our equity holders. Prior to the completion of this offering, Windsor Permian will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian will become subject to federal and state entity-level taxation. We will establish a net deferred tax liability for differences between the tax and book basis of our assets and liabilities, and we will record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at December 31, 2011 the amount of this charge would have been $26.2 million. It is anticipated that the company will be subject to a future, total combined federal and state income tax rate of 34% to 36%.

 

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Results of Operations

The following table sets forth selected historical operating data for the periods indicated.

 

		Year Ended December 31,
		2011				2010				2009
Operating Results:
Revenues
Oil and natural gas revenues		$	47,180,802			$	26,441,927			$	12,716,011
Other income			1,490,910				811,247				—
Operating expenses
Lease operating expense			10,345,355				4,588,559				2,366,623
Production taxes			2,333,853				1,346,879				663,068
Gathering and transportation expense			201,828				105,870				42,091
Oil and natural gas services			1,732,892				811,247				—
Depreciation, depletion and amortization			15,402,826				8,145,143				3,215,891
General and administrative			3,603,479				3,051,627				5,062,618
Asset retirement obligation accretion expense			63,259				37,856				27,934
Total expenses			33,683,492				18,087,181				11,378,225
Income from operations			14,988,220				9,165,993				1,337,786
Net interest income (expense)			(2,516,861	)			(801,791	)			24,137
Loss on derivative contracts			(13,009,393	)			(147,983	)			(4,068,005	)
Loss from equity investment			(7,017	)			—				—
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Production Data:
Oil (Bbls)			441,822				280,721				168,741
Natural gas (Mcf)			413,640				323,847				253,321
Natural gas liquids (Bbl)			86,815				79,978				70,384
Combined volumes (BOE)			597,577				414,674				281,345
Daily combined volumes (BOE/d)			1,637				1,136				771
Average Prices(1):
Oil (per Bbl)		$	92.26			$	76.51			$	58.01
Natural gas (per Mcf)			3.98				4.32				3.64
Natural gas liquids (per Bbl)			54.98				44.56				28.49
Combined (per BOE)			78.95				63.77				45.20
Average Costs (per BOE):
Lease operating expense		$	17.31			$	11.07			$	8.41
Gathering and transportation expense			0.34				0.26				0.15
Production taxes			3.91				3.25				2.36
Production taxes as a % of sales			4.9	%			5.1	%			5.2	%
Depreciation, depletion and amortization			25.78				19.64				11.43
General and administrative			6.03				7.36				17.99

 

(1)	After giving effect to our hedging arrangements in effect during 2009, the average prices per Bbl of oil and per BOE (on a combined basis), were $41.59 and $35.35, respectively, during that year. Average prices for our hydrocarbons were not impacted by our hedging arrangements during 2011 or 2010.

 

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Year ended December 31, 2011 Compared to Year ended December 31, 2010

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $20.8 million, or 78%, to $47.2 million for the year ended December 31, 2011 from $26.4 million for the year ended December 31, 2010. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 501 BOE/d during the year ended December 31, 2011 as compared to the same period in 2010. The total increase in revenue of approximately $20.8 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes and an increase in the prices of oil and natural gas liquids realized for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Production increased by 161,101 Bbls of oil, 6,837 Bbls of natural gas liquids and 89,793 Mcf of natural gas for the year ended 2011 as compared to the year ended 2010. The net dollar effect of the increase in prices of approximately $7.7 million (calculated as the change in year-to-year average prices times current year production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $13.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

		Change in prices				Production volumes at December 31, 2011(1)				Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil		$	15.75				441,822			$	6,959
Natural gas liquids		$	10.42				86,815			$	905
Natural gas		$	(0.34	)			413,640			$	(141	)
Total revenues due to change in price										$	7,723
		Change in production volumes(1)				Prices at December 31, 2010(2)				Total net dollar effect of change (in thousands)
Effect of changes in volumes:
Oil			161,101			$	76.51			$	12,326
Natural gas liquids			6,837			$	44.56			$	305
Natural gas			89,793			$	4.32			$	388
Total revenues due to change in volumes										$	13,019
Total change in revenues										$	20,742

 

(1)	Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.

(2)	Prices represent the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ended December 31, 2010.

Lease Operating Expense. Lease operating expense was $10.3 million ($17.31 per BOE) for the year ended December 31, 2011, an increase of $5.7 million, or 125%, from $4.6 million ($11.07 per BOE) for the year ended December 31, 2010. The increase is due to increased drilling activity, which resulted in additional producing wells for the year ended December 31, 2011 as compared to the year ended December 31, 2010. On a per-BOE basis, the increase is due to cost increases in services and supplies (primarily as a result of higher demand for such services and supplies in the Permian Basin and higher commodity prices), the cost of repairing and replacing downhole equipment due to rod and tubing configurations and pumping practices that resulted in a higher rate of well failures during 2011 and the associated downtime and loss of production as these failures were remediated. Our lease operating expense for the year ended December 31, 2011 was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on line in 2011. The processing cost of approximately $200,000 per month has been necessary to meet pipeline specifications.

 

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During the second quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reduce water trucking, respectively. We believe that our reduced well failure rate and the completion of the gathering systems will help reduce our lease operating expense on a per-BOE basis in future periods.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for the year ended December 31, 2011 as compared to 5.1% for the year ended December 31, 2010. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $1.0 million, or 73.3%, from $1.3 million during the year ended December 31, 2010 to $2.3 million during the year ended December 31, 2011 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $7.3 million, or 89.1%, from $8.1 million for the year ended December 31, 2010 to $15.4 million for the year ended December 31, 2011. The weighted average depletion rate was $25.40 per BOE for the year ended December 31, 2011 and $17.78 per BOE for the year ended December 31, 2010. The depletion rate increase was due primarily to an increase in costs and a decrease in proved reserves at December 31, 2011 for the reasons described in “Business—Oil and Gas Data” beginning on page 84 of this prospectus.

General and Administrative Expense. General and administrative expense increased $0.5 million from $3.1 million for the year ended December 31, 2010 to $3.6 million for the year ended December 31, 2011. A $1.9 million increase primarily attributable to salary and equity based compensation expense for our new executive team was partially offset by the capitalization of $0.9 million of such expense and a $0.5 million increase in COPAS overhead payments due to increased drilling activity.

Interest Expense. Interest expense for the year ended December 31, 2011 was $2.5 million, as compared to $0.8 million for the year ended December 31, 2010, an increase of $1.7 million. Our weighted average outstanding principal under our credit agreement was $69.0 million for the year ended December 31, 2011 as compared to $23.0 million for 2010 due to our increased drilling activity.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to our derivative contracts as of December 31, 2011 are Hess Corporation, or Hess, and BNP Paribas, or BNP, which we believe are acceptable credit risks.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

On October 4, 2011, in an effort to lock-in prices on our anticipated base level of production, while at the same time providing downside protection for our borrowing base, we entered into West Texas Intermediate light sweet crude oil swaps on the NYMEX with BNP for the calendar years 2012 and 2013 of 1,000 barrels per day priced at $78.50 and $80.55, respectively.

 

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Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2011. As of December 31, 2011, we had unrealized losses under all of our crude oil swaps. We may seek to settle some or all of these swaps after the closing of this offering with a portion of the net proceeds depending upon our assessment of market conditions.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				December 31, 2011
										Fair Value Liability
Crude Oil Swaps:
January — November 2012			335,000			$	78.50			$	6,833,265
December 2012			31,000				78.50				594,223
January — December 2013			365,000				80.55				5,544,350

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2011 and December 31, 2010.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
Description and Production Period														2011				2010
Oil Swaps:														Fair Value Liability				Fair Value Liability
December 2010			22,000			$	82.80			$	99.45-103.20			$	—			$	392,462
January — November 2011			180,000				82.90				98.50–102.20				—				4,159,695
December 2011			90,000				82.90				98.50–102.20				378,750				377,314
January — December 2012			270,000				85.07				98.25–101.80				3,876,959				3,844,101

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2011 and December 31, 2010.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
Description and Production Period														2011				2010
Oil Swaps:														Fair Value Asset				Fair Value Asset
December 2010			8,000			$	82.80				75.00			$	—			$	62,400
January — November 2011			82,500				82.90				78.42				—				369,205
December 2011			7,500				82.90				78.42				33,600				33,503
January — December 2012			90,000				85.07				80.52				409,380				406,489

 

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None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the loss on derivative contracts included in our consolidated statements of operations:

 

		Years Ended December 31,
		2011				2010				2009
Unrealized loss on open non-hedge derivative instruments		$	12,971,838			$	—			$	—
Unrealized loss on locked-in non-hedge derivative instruments			—				—				1,297,979
Loss on settlement of non-hedge derivative instruments			37,555				147,983				2,770,026
Loss on derivative contracts		$	13,009,393			$	147,983			$	4,068,005

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $2.3 million and $6.5 million as of December 31, 2011 and 2010, respectively, which earns interest that is remitted to us. Under our master netting agreement with Hess, we have offset this margin deposit against its derivative positions.

Year ended December 31, 2010 Compared to Year ended December 31, 2009

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $13.7 million, or 108%, to $26.4 million during the year ended December 31, 2010 from $12.7 million for the year ended December 31, 2009. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 365 BOE/d during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The total increase in revenue of approximately $13.7 million is largely attributable to higher oil, natural gas liquid and natural gas production volumes as well as an increase in oil, natural gas liquid and natural gas prices realized for the year ended December 31, 2010 as compared to year ended December 31, 2009. Production increased by 111,980 Bbls of oil, 9,594 Bbls of natural gas liquids and 70,526 Mcf of natural gas during 2010 as compared to 2009. The net dollar effect of the increase in prices of approximately $6.7 million (calculated as the change in year-to-year average prices times current year production volumes for oil, natural gas liquids and natural gas) and the net dollar effect of the change in production of approximately $7.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

		Change in prices				Production volumes at December 31, 2010(1)				Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil		$	18.50				280,721			$	5,193
Natural gas liquids		$	16.07				79,978			$	1,285
Natural gas		$	0.68				323,847			$	220
Total revenues due to change in price										$	6,698
		Change in production volumes(1)				Prices at December 31, 2009				Total net dollar effect of change (in thousands)
Effect of changes in volumes:
Oil			111,980			$	58.01			$	6,496
Natural gas liquids			9,594			$	28.49			$	273
Natural gas			70,526			$	3.64			$	257
Total revenues due to change in volumes										$	7,026
Total change in revenues										$	13,724

 

(1)	Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.

 

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Lease Operating Expense. Lease operating expense was $4.6 million ($11.07 per BOE) for the year ended December 31, 2010, an increase of $2.2 million, or 92%, from $2.4 million ($8.41 per BOE) for the year ended December 31, 2009. The increase is due to increased drilling activity, which resulted in additional producing wells in 2010 as compared to 2009. On a per-BOE basis, the increase is due to cost increases in services and supplies, primarily as a result of the increased demand for such services and supplies in the Permian Basin, and increased commodity prices as well as additional well failure repairs coupled with downtime associated with the failures impacting production.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 5.1% for the year ended December 31, 2010 as compared to 5.2% for the year ended December 31, 2009. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $0.6 million, or 86%, from $0.7 million for the year ended December 31, 2009 to $1.3 million for the year ended December 31, 2010 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.9 million, or 153%, from $3.2 million for the year ended December 31, 2009 to $8.1 million for the year ended December 31, 2010. The weighted average depletion rate was $11.21 per BOE in 2009 and $17.78 per BOE in 2010. The higher depletion rate in 2010 was due primarily to downward reserve revisions due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded additional proved reserves and utilized the additional proved reserves in our depletion computation for 2009. Our 2009 depletion expense rate was $11.21 per BOE, which is lower in part due to these additional proved reserves.

General and Administrative Expense. General and administrative expense decreased $2.0 million, or 39%, from $5.1 million for the year ended December 31, 2009 to $3.1 million for the year ended December 31, 2010. This decrease was primarily due to a reduction in our labor force. As our capital expenditure programs result in increased production levels, we expect that general and administrative expense per unit of production will continue to decrease.

Interest Expense. Interest expense for 2010 was $0.8 million as compared to an interest expense of $0.01 million for 2009. During the year ended December 31, 2010, $0.2 million of our interest was capitalized and our weighted average outstanding principal under our credit agreement was $23.0 million, which was used primarily to fund our increased drilling program. During the year ended December 31, 2009, most of the interest was capitalized and our weighted average outstanding principal was $6.7 million.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparty to all of our derivative contracts is Hess, which we believe is an acceptable credit risk.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps. We have not entered into any new swap contracts since the initial contract in December 2007. As of December 31, 2010 and 2009, all swap contracts were locked-in with counter swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2010 and 2009.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2010				2009
Description and Production Period														Fair Value Liability				Fair Value Liability
Oil Swaps:
December 2009			22,000			$	83.75			$	102.25 – 105.90			$	—			$	432,550
January — November 2010			242,000				82.80				99.45 – 103.20				—				4,312,111
December 2010			22,000				82.80				99.45 – 103.20				392,462				390,714
January — December 2011			270,000				82.90				98.50 – 102.20				4,537,009				4,485,047
January — December 2012			270,000				85.07				98.25 – 101.80				3,844,101				3,737,855

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2010 and 2009.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2010				2009
Description and Production Period														Fair Value Asset				Fair Value Asset
Oil Swaps:
December 2009			8,000			$	83.75			$	71.03			$	—			$	101,757
January — November 2010			88,000				82.80				75.00				—				685,405
December 2010			8,000				82.80				75.00				62,400				62,108
January — December 2011			90,000				82.90				78.42				402,708				397,880
January — December 2012			90,000				85.07				80.52				406,489				394,696

None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations as follows:

 

		Years ended December 31,
		2010				2009
Unrealized loss on locked-in non-hedge derivative instruments		$	—			$	1,297,979
Loss on settlement of non-hedge derivative instruments			147,983				2,770,026
Loss on derivative contracts		$	147,983			$	4,068,005

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $6.5 million and $10.3 million as of December 31, 2010 and 2009, respectively. Interest earned on the deposit is remitted to us. As we have a master netting agreement with Hess, we have offset this margin deposit against derivative positions.

 

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Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from our equity holder, borrowings under our credit facility and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We regularly evaluate potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Liquidity and cash flow

Our cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:

 

		Year Ended December 31,
		2011				2010				2009
Net cash provided by operating activities		$	30,384,194			$	5,175,824			$	2,701,566
Net cash used in investing activities			(76,314,042	)			(53,134,641	)			(32,149,617	)
Net cash provided by financing activities			48,642,492				49,618,254				23,849,250
Net change in cash		$	2,712,644			$	1,659,437			$	(5,598,801	)

Operating Activities

Net cash provided by operating activities was $30.4 million for the year ended December 31, 2011 as compared to $5.2 million for the year ended December 31, 2010. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 59. The increase in production is largely a result of our increased drilling activities throughout 2011.

Net cash provided by operating activities was $5.2 million for the year ended December 31, 2010 as compared to $2.7 million for the year ended December 31, 2009. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 59. The increase in production volumes is largely a result of our increased drilling program in 2010. The increase in operating activities was partially offset by changes in our working capital components in 2010 which consisted primarily of the purchase of inventory of tubular goods for our drilling program and increased accounts receivables due to the increase in our drilling activities in 2010.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $76.3 million, $53.1 million and $32.1 million during the years ended December 31, 2011, 2010 and 2009, respectively.

During 2011, we spent $72.2 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 54 gross (31 net) wells. We spent an additional $3.2 million on leasehold costs, $4.1 million for the purchase of certain assets, real estate and leasehold interests which were subsequently

 

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contributed to Muskie and $2.9 million for the purchase of drilling rigs and other equipment which were subsequently contributed to Bison. These amounts were partially offset by proceeds of $6.0 million from a partial sale of our equity investment, $0.05 million from the sale of property and equipment and $0.08 million from the settlement of non-hedge derivative investments and margin deposits.

During 2010, we spent $39.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 40 gross (25 net) wells. We spent an additional $3.5 million for the purchase and development of leasehold interests, $11.7 million for the purchase of drilling rigs, well servicing equipment and other equipment which were subsequently contributed to Bison and $0.2 million for the settlement of non-hedge derivative instruments and margin deposits. These amounts were partially offset by the $1.3 million we received from the sale of approximately 10,946 net acres of non producing acreage in the Permian Basin.

During 2009, we spent $24.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 12 gross (nine net) wells. We spent an additional $2.7 million for the purchase and development of leasehold interests in the Permian Basin and $5.5 million for the net amount of the settlement of non-hedge derivative instruments and margin deposits.

Our investment activities for the years ended December 31, 2011, 2010 and 2009 are summarized in the following table:

 

		Year Ended December 31,
		2011				2010				2009
Drilling and completion of wells		$	(72,165,677	)		$	(38,979,629	)		$	(23,955,667	)
Proceeds from leasehold acquisitions			(3,213,932	)			(3,493,464	)			(2,667,068	)
Purchase of other property and equipment			(7,064,972	)			(11,741,073	)			(8,856	)
Proceeds from sale of property and equipment			54,909				1,270,075				2,000
Settlement of non-hedge derivative instruments			(4,126,800	)			(3,962,440	)			(2,770,026	)
Receipt (payment) on derivative margins			4,202,467				3,771,890				(2,750,000	)
Proceeds from equity investment, net			5,999,963				—				—
Net cash used in investing activities		$	(76,314,042	)		$	(53,134,641	)		$	(32,149,617	)

Financing Activities

Net cash provided by financing activities for 2011 was $48.6 million as compared to $49.6 million for 2010. During 2011, we borrowed $40.2 million under our revolving credit facility and received capital contributions from entities controlled by Wexford, our equity sponsor, of $9.2 million. These proceeds were used primarily to fund our drilling costs and purchase property and equipment.

Net cash provided by financing activities for 2010 was $49.6 million as compared to $23.8 million for 2009. The net cash provided by financing activities in 2010 is primarily attributable to borrowings of $61.1 million under our revolving credit facility, partially offset by principal payments of $24.0 million under our prior credit facility with the Bank of Oklahoma, N.A. During 2010, we received capital contributions from entities controlled by Wexford, our equity sponsor, of $18.8 million which were partially offset by distributions to Wexford of $5.6 million. We paid $0.7 million in debt issuance costs in 2010. We used the net proceeds from our financing activities during 2010 to fund our drilling costs, the purchase of property and equipment, the purchase of tubular goods inventory and the acquisition and development of leasehold.

Net cash provided by financing activities for 2009 was $23.8 million as compared to $80.2 million for 2008. The net cash provided by financing activities in 2009 is attributable to borrowings of $7.7 million under our

 

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revolving credit facility and $16.9 million of capital contributions from entities controlled by Wexford, our equity sponsor, which amounts were partially offset by distributions to Wexford of $0.6 million. We paid $0.1 million for debt issuance costs and costs relating to the preparation for the initial public offering. We used the net proceeds from our financing activities to fund our drilling program, the purchase of property and equipment, the acquisition and development of leasehold and the settlement of our non-hedge derivative instruments.

Existing Revolving Credit Facility

On October 15, 2010, we entered into a senior secured revolving credit agreement with BNP Paribas, or BNP, as administrative agent for the several lenders, providing for a $100.0 million revolving credit facility, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves. The outstanding borrowings bear interest at a rate elected by us that is currently based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal is payable voluntarily or is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, and (b) at the maturity date of October 14, 2014. We are obligated to pay a quarterly commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of our assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st. In addition, we may request up to three additional redeterminations of the borrowing base between scheduled redeterminations. The borrowing base was $45.0 million at December 31, 2010. The borrowing base was increased several times during 2011 as a result of redeterminations and at December 31, 2011 the borrowing base was $100.0 million. Under the terms of the revolving credit agreement as currently in effect, the borrowing base will remain at $100.0 million through October 15, 2012, at which time the borrowing base will be reduced to $85.0 million, subject to the periodic and elective borrowing base redeterminations described above. However, we expect that our borrowing base will be increased as a result of our acquisition of the oil and gas properties subject to the Gulfport contribution and those properties owned by Windsor UT. As of December 31, 2011, we had outstanding borrowings of $85.0 million, which bore interest at a weighted average rate of 3.3%.

Our revolving credit agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of various financial ratios described below.

 

Financial Covenant		Required Ratio
Ratio of EBITDAX to interest expense(1)		Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX		Not greater than 3.5 to 1.0
Ratio of current assets to liabilities		Not less than 1.0 to 1.0

 

(1)

Our revolving credit agreement defines EBITDAX, for any period, as the sum of our consolidated net income for such period plus the following expenses or charges to the extent deducted from our consolidated net income in such period: interest, income taxes, depreciation, depletion, amortization, exploration expenses, extraordinary items and other similar noncash charges, minus all noncash income added to our consolidated net income.

As of December 31, 2011, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence of any event of default unless we cure any such default within any applicable cure period. For payments of interest under our revolving credit facility, we have a three business day grace period, and a 30-day cure period for most covenant defaults, except for defaults of certain covenants, including the financial covenants and negative covenants under our revolving credit facility.

 

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Prior Revolving Credit Facility

On September 17, 2009, we entered into a revolving credit facility with the Bank of Oklahoma, N.A., or BOK. The BOK revolving credit facility had a maximum principal amount of $50.0 million, subject to a collateral borrowing base calculation which was based on the underlying reserve value of the oil and natural gas properties securing the credit facility and outstanding letters of credit. The BOK revolving credit facility was repaid in full in October 2010 with borrowings under the BNP revolving credit facility and then terminated.

Borrowings under the BOK revolving credit facility bore interest at our election of either BOK’s listed national prime rate plus an interest rate spread ranging from 1.0% to 2.5% (based on borrowing levels) payable monthly or at LIBOR rates plus an interest rate spread ranging from 2.5% to 4.0% (based on borrowing levels) payable at the end of the applicable interest period. The credit facility agreement allowed BOK to charge a 0.25% commitment fee on the unused available borrowing.

The BOK revolving credit facility was collateralized by oil and natural gas properties and contained certain financial and non-financial covenants, which included: providing quarterly financial statements and annual audited financial statements; providing semi-annual reserve engineering reports; restrictions on distributions to members; restrictions on incurring additional debt; restrictions on financial derivative contracts; maintaining a funded debt to earnings before hedge gains or losses, asset gains or losses, depreciation, depletion, amortization and interest expense of no greater than 3.0 to 1.0.

Capital Requirements and Sources of Liquidity

We currently anticipate our 2012 capital budget for drilling and infrastructure will be approximately $180.0 million after giving effect to the Contributions. We intend to allocate these expenditures as follows:

 

•

$158.0 million for the drilling and completion of operated wells;

 

•

$8.0 million for our participation in the drilling and completion of non-operated wells;

 

•

$8.0 million for leasehold acquisitions; and

 

•

$6.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

However, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2012 capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Based upon current oil and natural gas price expectations for 2012, we believe that our cash flow from operations, proceeds of this offering and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next 12 months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our capital expenditure budget for 2012 does not allocate funds to any leasehold interest and property acquisitions. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will

 

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be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2011:

 

		Payments Due By Year
		Less Than 1 Year				1-3 Years				3-5 Years				More Than 5 Years				Total
		(in thousands)
Long term debt(1)		$	—			$	85,000			$	—			$	—			$	85,000
Derivative contracts			8,320				6,139				—				—				14,459
Asset retirement obligation(2)			—				—				—				1,080				1,080
Operating leases			219				690				358				—				1,267
Total		$	8,539			$	91,829			$	358			$	1,080			$	101,806

 

(1)

Consists of the outstanding principal amount at December 31, 2011 under our revolving credit facility. This table does not include future commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. All borrowings under our revolving credit facility are due on October 14, 2014.

(2)

Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. Please read Note 4 to our audited financial statements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of the notes to our consolidated financial statements appearing elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by management.

Use of Estimates

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision

 

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become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Method of accounting for oil and natural gas properties

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on a quarterly basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three years.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and

 

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production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when our volumes exceed our estimated remaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did not have any gas imbalances as of December 31, 2011, 2010 and 2009. Revenues from oil and natural gas services are recognized as services are provided.

Impairment

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, effective December 31, 2009, prices are calculated as the average oil and gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Asset retirement obligations

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method.

We determine the asset retirement obligation by calculating the present value of estimated cash flows related to the liability. Estimating the future asset retirement obligation requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment is made to the related asset.

Derivatives

From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent

 

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changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. For those derivative instruments that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. Changes in the fair value of instruments designated as a fair value hedge offset changes in the fair value of the hedge item and changes in the fair value of instruments designated as cash flow hedges are shown in accumulated other comprehensive income until the hedged item is recognized in earnings. For derivative instruments not designated as hedging instruments, the unrealized gain or loss on the change in fair value of these instruments are recognized in earnings during the period of change. None of our derivatives were designated as hedging instruments during the years ended December 31, 2011, 2010 and 2009.

Equity-Based Compensation

During the year ended December 31, 2011, we granted to our executive officers options to acquire membership interests in our Company. Such options vest in four equal annual installments commencing on the first anniversary of the date of grant and are exercisable for five years from the date of grant. Generally, in the event more than 50% of the combined voting power of our Company is not owned by Wexford or its affiliates and there is a material change in the terms of the option holder’s employment, the options will vest immediately. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

 

Months Ended		Membership Interests Granted				Exercise Price				Fair Value at Date of Grant
April 2011			1.00	%		$	3,600,000			$	1,452,851
August 2011			1.20	%			6,000,000				1,383,976
September 2011			1.25	%			5,900,000				1,532,612
November 2011			0.25	%			1,250,000				288,328
			3.70	%		$	16,750,000			$	4,657,767

At December 31, 2011, for outstanding options, the intrinsic value was $112,500 and the weighted-average remaining contractual terms were 4.6 years. Also, at December 31, 2011, no options were exercisable.

We account for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost is recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price and our expectations regarding dividends.

We do not have a history of market prices for our membership interests because such interests are not publicly traded. We utilized the observable data for a group of peer companies that grant options to assist in developing our volatility assumption. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual terms of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. We do not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

 

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A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 is as follows:

		Year Ended December 31, 2011
Expected term			5 years
Risk-free interest rate			0.96	%
Expected volatility			45.50	%
Expected dividend yield			0.00	%

As of December 31, 2011, we assumed no annual forfeiture rate because of our lack of turnover and lack of history for this type of award. We will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover behavior and other factors. Changes in the estimated forfeiture rate can have a significant effect on reported equity-based compensation expense, because the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed.

We perform annual valuations to estimate our enterprise value. Our valuations consider a number of objective and subjective factors that we believe market participants would consider, including: (a) our business, financial condition, and results of operations, including related industry trends affecting our operations; (b) our forecasted operating performance and projected future cash flows; (c) the liquid or illiquid nature of our membership interest; (d) liquidation preferences, redemption rights and other rights and privileges of our membership interest; (e) market multiples of our most comparable public peers; and (f) market conditions affecting our industry.

We used the income approach to estimate our enterprise value. The income approach involves applying an appropriate risk-adjusted discount rate to projected cash flows based on forecasted revenue and costs. The valuations were based primarily on our independent engineering oil and gas reserve reports which are generally a cash flow model of the Company. There were no significant events during the year that caused us to adjust these values at the various grant dates.

There is inherent uncertainty in our forecasts and projections and, if we had made different assumptions and estimates than those described previously, the amount of our equity-based compensation expense could have been materially different.

Equity-based compensation expense recorded for the year ended December 31, 2011 was $544,290. The unrecognized equity-based compensation expense as of December 31, 2011 was $4,113,477 related to these awards which is expected to be recognized over a weight-average period of 3.6 years. No equity-based compensation expense was recorded for the years ended December 31, 2010 and 2009 as we had not historically issued equity-based compensation awards.

Recent accounting pronouncements

Fair Value

In May 2011, the FASB issued authoritative guidance which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this update will not have a significant impact on our financial statements.

 

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Comprehensive Income

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income.” The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2009, 2010 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosure about Market Risks

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. For the purpose of locking-in the value of a swap, we enter into counter-swaps from time to time. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we placed a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. In October 2011 we placed a swap contract covering 730,000 Bbls of crude oil for the period from January 2012 to December 2013 at a fixed price of $78.50 for 2012 and $80.55 for 2013. Such contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil.

At December 31, 2011, we had a net liability derivative position of $14.5 million related to our price swap derivatives.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $12.7 million at December 31, 2011) and receivables from the sale of our oil and natural gas production (approximately $5.0 million at December 31, 2011).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At each of December 31, 2011 and 2010, we had one customer that represented approximately 68% and 62%, respectively, of our total joint operations receivables. Prior to 2010, we did not operate the wells and, therefore, did not have joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility with BNP. The terms of our revolving credit facility with BNP provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Borrowings under the credit facility bore interest at a weighted average rate of 3.3% as of December 31, 2011. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $850,000 annually, based on the $85.0 million outstanding in the aggregate under our revolving credit facility with BNP as of December 31, 2011, and assuming no interest is capitalized. Pending use of the net proceeds from this offering to fund our exploration and development activities and for general corporate purposes, we intend to repay outstanding borrowings under our revolving credit facility with BNP.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements. Please read Note 11 to our consolidated financial statements included elsewhere in this prospectus for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

 

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BUSINESS

General

Overview

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,174 net acres with production at the time of acquisition of approximately 800 BOE/d from 33 gross (16.5 net) wells in the Permian Basin. Subsequently, we acquired approximately 25,851 additional net acres, which brought our total net acreage position in the Permian Basin to 30,025 net acres at March 31, 2012 and, after giving effect to the Contributions, we had 49,703 net acres. We are the operator of approximately 99% of this acreage. As of March 31, 2012, after giving effect to the Contributions, we had drilled 147 gross (136 net) wells, and participated in an additional 11 gross (five net) non-operated wells, in the Permian Basin. Of these 158 gross wells, 149 were completed as producing wells and nine were in various stages of completion. In the aggregate, as of March 31, 2012, we held interests in 182 gross (166 net) producing wells in the Permian Basin.

We built our leasehold position through the following acquisitions and development activities in the Wolfberry play:

 

•

In 2008, we acquired 6,247 net acres at the Spanish Trail and Munn prospects in Midland County, Texas through 11 leases and one mineral deed, with 5,146 net acres attributable to one lease;

 

•

Commencing in 2008 and ending in 2010, we acquired leases at the Barron prospect in Midland County, Texas covering 225 net acres;

 

•

Commencing in 2008 and ending in 2011, we acquired leases at the Gist prospect in Ector County, Texas covering 1,404 net acres;

 

•

In 2008, 2009 and 2011, we acquired 35 leases at the UL prospect in Andrews and Upton Counties, Texas covering a total of 9,966 net acres;

 

•

Beginning in 2008, we acquired 17 leases at the Hurt/WHL prospect in Ector County, Texas covering 2,779 net acres;

 

•

In 2009, we acquired one lease at the Cumberland prospect located in Midland County, Texas covering 207 net acres;

 

•

In 2010, we acquired leases at the North Howard prospect located in Howard County, Texas and currently cover 176 net acres;

 

•

In 2010, we acquired 912 net acres at the Sabo prospect in Upton County, Texas;

 

•

In 2010 and 2011, we acquired 150 leases at the Big Max prospect located in Andrews County, Texas covering 825 net acres; and

 

•

In 2011, we acquired three leases in the Clete prospect in Crockett County, Texas covering 3,110 net acres.

Our activities are primarily focused on the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations, which we refer to collectively as the Wolfberry play. The Wolfberry play is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. The Wolfberry play is a modification and extension of the Spraberry play, the majority of which is designated in the Spraberry Trend area field. According to the U.S. Energy Information Administration, the Spraberry trend area ranks as the second largest oilfield in the United States, based on 2009 reserves.

 

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As of December 31, 2011, our estimated proved oil and natural gas reserves pro forma for the Contributions were 39,460 MBOE based on reserve reports prepared by Ryder Scott Company L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 21.7% are classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate are from 329 gross well locations on 40-acre spacing. As of December 31, 2011, these proved reserves were approximately 67% oil, 20% natural gas liquids and 13% natural gas.

We have 977 identified potential vertical drilling locations based on our evaluation of applicable geologic and engineering data, and we have an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Our estimated ultimate recoveries, or EURs, from future PUD wells, as estimated by Ryder Scott, range from 89 MBOE to 147 MBOE per well, with an average EUR per well of 127 MBOE. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells in the Wolfberry play. We are currently using four drilling rigs and intend to add two additional rigs later in 2012.

We believe the experience gained from our historical drilling programs and the information obtained from the results of extensive industry drilling activity in the Permian Basin have helped us reduce the risk and uncertainity associated with drilling vertical wells on our Permian Basin acreage. We intend to supplement our vertical development drilling activity with horizontal wells targeting various intervals in the Wolfberry play. Our horizontal drilling program is intended to further capture the upside potential that may exist on our properties and increase our well performance and recoveries as compared to drilling vertical wells alone.

During 2011, we assembled a new executive team and, beginning with the fourth quarter of 2011, this team assumed management control of our operations and development activities in the Permian Basin. With an average of approximately 26 years of industry experience per person, this team has extensive experience in the Permian Basin as well as other resource plays in North America, including significant experience in drilling and completing horizontal wells. Under the direction of our new executive team, the average drilling time required to reach total depth, or TD, was shortened by 25% to 15 days during the fourth quarter of 2011 from 20 days during the second quarter of 2011, reducing average drilling costs (excluding completion costs) by 8.3% from $1.2 million to $1.1 million period-to-period, while also decreasing the time from spud to spud to 23 days from 25 days. Also, during the quarter ended March 31, 2012 our average daily production, pro forma for the Contributions, was 3,280 BOE/d, an increase of 11%, or 333 BOE/d, from 2,947 BOE/d for the quarter ended December 31, 2011. This increase was due primarily to improved strategies and procedures introduced by our new executive team relating to wellbore configuration, completion, execution, fluid recovery and well pumping practices that significantly reduced the level of required well remediation and the associated loss of production. We anticipate further increases in efficiencies as our new executive team executes on our development strategies across our acreage base.

The following table provides a summary of selected operating information of our properties, pro forma for the Contributions. The information is as of March 31, 2012 except as otherwise noted.

 

Basin		Net Acreage				Average Working Interest				Identified Potential Drilling Locations(1)								2012 Budget												Estimated Net Proved Reserves at December 31, 2011								Average Daily Production (BOE/d)(3)
										Gross				Net				Gross Wells(2)				Net Wells(2)				Capex (In millions)				MBOE				% Developed
Permian			49,703				86.2	%			977				926				90				75			$	180.0				39,460				24				3,378

 

(1)

Reflects identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data. We have an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

 

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(2)	Includes 81 gross (72 net) wells for which we are the operator and nine gross (three net) non-operated wells.

(3)	During February 2012.

Our current exploration and development budget for our oil and natural gas properties for the year ending December 31, 2012 is approximately $180.0 million. In 2012, we plan to spend approximately $158.0 million on the drilling and completion of 72 gross (65 net) operated vertical wells and nine gross and eight net horizontal wells, $8.0 million for the drilling and completion of nine non-operated wells, $8.0 million for leasehold acquisitions and $6.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

Our Business Strategy

Our business strategy is to increase stockholder value through the following:

 

•

Grow production and reserves by developing our oil-rich resource base. We intend to actively drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. As of March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,162 such locations based on 20-acre downspacing. We believe the drilling of these locations will provide us with the critical subsurface data necessary to target potential horizontal horizons. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells in the Wolfberry play. We ended 2011 with a two rig drilling program and are currently using four drilling rigs. We intend to add two additional rigs later in the year. Subject to market conditions and rig availability, we expect to operate up to eight rigs in 2013, which we expect will allow us to significantly increase our drilling program in 2013.

 

•

Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We believe there are opportunities to target various intervals in the Wolfberry play with horizontal wells and we currently plan to drill nine gross (eight net) horizontal wells in 2012 to target these producing horizons. Our horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, we believe increased well density opportunities may exist across our acreage base. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place.

 

•

Focus on enhancing advanced drilling and completion techniques to maximize recovery. Our eight member executive team, which has an average of approximately 26 years of industry experience per person, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach TD for our vertical Wolfberry wells decreased from an average of 20 days during the second quarter of 2011 to an average of 15 days during the fourth quarter of 2011, resulting in a lower total well cost. Our focus on efficient drilling and completion techniques, and the resulting reduction in time to reach TD, is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. In addition, we believe that the experience of our new executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well paths. Additionally, our completion techniques are continually evolving as we evaluate hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

 

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•

Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. In the current commodity price environment, our oil and liquids rich asset base provides attractive returns. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 99% of our acreage. This operational control allows us to more efficiently manage the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 86.2% working interest in our acreage pro forma for the Contributions allows us to realize the majority of the benefits of these expected improvements and cost efficiencies.

 

•

Pursue strategic acquisitions with exceptional resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that we believe have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We intend to continue to pursue acquisitions that meet our strategic and financial targets.

 

•

Maintain Financial flexibility. We seek to maintain a conservative financial position. As of December 31, 2011, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowing under our revolving credit facility, we would have had approximately $             million of available borrowing capacity under such facility. We expect that we will fund our capital development plans for 2012 from our operating cash flow and borrowings under our revolving credit facility. We intend to use the net proceeds from this offering to repay borrowings outstanding under our revolving credit facility pending their use to fund our capital expenditures.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

 

•

Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. As of April 27, 2012, the Baker Hughes Rig Count survey reported that there were 510 rigs drilling in the Permian Basin. The majority of our current properties are well positioned in the core of the Wolfberry play. We believe that our historical vertical development success will be complemented with horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Our production for the year ended December 31, 2011 was approximately 74% oil, 15% natural gas liquids and 11% natural gas. As of December 31, 2011, our estimated net proved reserves were comprised of approximately 68% oil and 19% natural gas liquids. This oil and liquids exposure allows us to benefit from their currently more favorable prices as compared to natural gas.

 

•

Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for oil-weighted reserves that we believe provides attractive growth and return opportunities. As of March 31, 2012, after giving effect to the Contributions, we had 977 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. In 2012, after giving effect to the Contributions, we anticipate drilling 72 gross (65 net) vertical operated wells and nine gross (eight net) horizontal operated wells, which represent only approximately 7.4% of our identified vertical potential drilling locations at March 31, 2012. We also believe that there are multiple horizontal locations that could be drilled on our acreage. In addition, the liquids rich natural gas component of our inventory adds value with Btu content ranging from 1,243 MMBtu to 1,578 MMBtu and our March 2012 natural gas liquids yield was 125 Bbls/MMcf. In addition, we have approximately 117 square miles of proprietary 3-D seismic data covering our acreage. This data

 

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facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including horizontal drilling opportunities and strategic leasehold acquisitions.

 

•

Experienced, incentivized and proven management team. Our new executive team has an average of approximately 26 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our future development plans to include horizontal drilling. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

 

•

Favorable and stable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With over 400,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.

 

•

High degree of operational control. We are the operator of approximately 99% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processees. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

 

•

Financial flexibility to fund expansion. Upon the completion of this offering, we will have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to actively develop our drilling, exploitation and exploration activities in the Wolfberry play and maximize the present value of our oil-weighted resource potential. As of December 31, 2011, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowings under our revolving credit facility, we would have had approximately $             million of available borrowing capacity under our revolving credit facility. We expect that our borrowing base will be increased as a result of the Contributions.

Our Properties

Review of Exploration, Exploitation and Development Activities

The following table summarizes certain operating information of our properties, pro forma for the Contributions. The information is as of March 31, 2012 except as otherwise noted.

 

		Net Acreage				Average Working Interest				Identified Potential Drilling Locations(1)								2012 Budget												Estimated Net Proved Reserves at December 31, 2011								Average Daily Production (BOE/d)(3)
Basin										Gross				Net				Gross Wells(2)				Net Wells(2)				Capex (In millions)				MBOE				% Developed
Permian			49,703				86.2	%			977				926				90				75			$	180.0				39,460				24				3,378

 

(1)

Reflects identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data. We have an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

(2)	Includes 81 gross (72 net) wells for which we are the operator and nine gross (three net) non-operated wells.

(3)	During February 2011.

 

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Permian Basin

Location and Land

We acquired approximately 4,174 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, with an effective date of November 1, 2007, from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers. Subsequently, we acquired approximately 25,851 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 30,025 net acres at March 31, 2012 and, after giving effect to the Contributions, we will have 49,703 net acres. Since our initial acquisition in the Permian Basin through March 31, 2012, we drilled or participated in the drilling of 152 gross (81 net) wells (or 158 gross (141 net) wells after giving effect to the Contributions) on our leasehold in this area, primarily targeting the Wolfberry play. We are the operator of approximately 99% of our Permian Basin acreage. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States.

Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.

The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.

During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet, with an additional 200 to 300 feet drilled to produce from the upper portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatments across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized approximately 15% of their acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recovery techniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Wolfberry play. As of March 31, 2012, we held interests in 181 gross (165 net) producing wells.

Geology

The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita fold belt. It is one of the largest sedimentary basins in the U.S., and has oil and gas production from several reservoirs from Permian through Ordovician in age. The term “Wolfberry” was coined initially to indicate commingled production from the Permian Spraberry, Dean and Wolfcamp formations. In this prospectus, we refer to the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations collectively as the Wolfberry play. The Wolfberry play of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp play. The Spraberry was

 

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deposited as turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirs consist of debris-flow and grain-flow sediments, which were also deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp are generally found in proximity to the Central Basin Platform, while the shale reservoirs within the Wolfcamp thicken basinward away from the Central Basin Platform. Both the Spraberry and Wolfcamp contain organic-rich mudstones and shales which, when buried to sufficient depth for maturation, became the source of the hydrocarbons found in the reservoirs.

The Wolfberry play can be generally characterized as a combination of low-permeability clastic, carbonate and shale reservoirs which are hydrocarbon-charged and are economic due to the overall thickness of the section (more than 3,000 feet) and application of enhanced stimulation (fracking) techniques. The Wolfberry is an unconventional “basin-centered oil” resource play, in the sense that there is no regional downdip oil/water contact.

Several shale intervals within the Wolfcamp formation are currently being evaluated for horizontal development potential, with initial drilling expected in 2012. The shales exhibit micro-darcy permeabilities, which result in relatively small drainage areas and recovery factors. Because of this, the horizontal exploitation of these reservoirs will supplement, and not replace, the vertical development program.

There are also productive carbonate and shale intervals within the shallower Permian Clearfork formation. Two shale intervals within the Clearfork formation are currently being evaluated for potential horizontal development. Below the Wolfcamp formation lie the Pennsylvanian Strawn and Atoka formations. Although difficult to predict, there are conventional pay intervals that develop locally within these formations which, when present, can add significant reserves.

Debris flows within the Spraberry and Wolfcamp carbonates have been observed on 3-D seismic surveys. Initial tests have confirmed the presence of enhanced reservoir. Additionally, structural closures have been mapped and are being evaluated for drilling to test deeper targets. Our extensive geophysical database, which includes approximately 117 square miles of proprietary 3-D seismic data, will be used to highgrade future locations.

Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to our interest in these assets were approximately 24,750 MBOE, of which 22.0% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 293 gross well locations on 40-acre spacing. The proved reserves are generally characterized as long-lived, with predictable production profiles.

Production Status

In February 2012, net production from our Permian Basin acreage, pro forma for the Contributions, was 97,967 BOE, or an average of 3,378 BOE/d, of which 72% was oil, 16% was natural gas liquids and 12% was natural gas. From January 1, 2011 through December 31, 2011, our average daily net production from our Permian Basin acreage, pro forma for the Contributions, was 2,514 BOE/d, of which 71% was from oil, 17% was from natural gas liquids and 12% was from natural gas.

Facilities

Our land oil and gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.

Recent and Future Activity

During 2011, 56 gross (32 net) wells were drilled on our Permian Basin acreage for an aggregate estimated net cost of $82.2 million. On a pro forma basis after giving effect to the Contributions, 58 gross (50 net) wells were drilled on our Permian acreage during 2011. As of December 31, 2011, we had 977 identified

 

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potential vertical drilling locations based on 40-acre spacing and an additional 1,162 identified potential vertical drilling locations based on 20-acre downspacing. We currently expect to drill an estimated 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells on our acreage in 2012. The wells are expected to be drilled to approximately 11,200 feet at an estimated average completed gross well cost of approximately $1.9 million to $2.4 million per vertical well and $6.0 million to $7.0 million per horizontal well. In this prospectus, we define identified potential drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data on 40-acre or 20-acre downspacing as indicated. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Oil and Gas Data

Proved Reserves

SEC Rule-Making Activity

In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the following:

 

•

Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.

 

•

Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

 

•

Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

 

•

Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

 

•

Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We adopted the rules effective December 31, 2009, as required by the SEC.

Evaluation and Review of Reserves

Our historical reserve estimates were prepared by Ryder Scott as of December 31, 2011 and by Pinnacle as of December 31, 2010 and 2009, in each case with respect to our assets in the Permian Basin. Reserve estimates for properties attributable to Windsor UT and the properties subject to the Gulfport contribution were prepared, in each case, by Ryder Scott as of December 31, 2011.

Each of Ryder Scott and Pinnacle is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing

 

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of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither independent third-party engineering firm owns an interest in any of our properties or is employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our 2011 proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Vice President—Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Vice President—Reservoir Engineering is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 26 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

 

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The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

•

review and verification of historical production data, which data is based on actual production as reported by us;

 

•

preparation of reserve estimates by our Vice President—Reservoir Engineering or under his direct supervision;

 

•

review by our Vice President—Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

 

•

direct reporting responsibilities by our Vice President—Reservoir Engineering to our Chief Executive Officer; and

 

•

verification of property ownership by our land department.

The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves as of December 31, 2011, based on the reserve report prepared by Ryder Scott, and as of December 31, 2010 and 2009, based on the reserve reports prepared by Pinnacle, each an independent petroleum engineering firm, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. All our proved reserves included in the reserve reports are located in North America. Ryder Scott and Pinnacle prepared all our reserve estimates as of the periods covered by their respective reports. The following table also sets forth estimates of our net proved oil and natural gas reserves as of December 31, 2011 on a pro forma basis after giving effect to the contribution of Windsor UT to Windsor Permian and the Gulfport contribution as if they had occurred on December 31, 2011. The reserves attributable to the Windsor UT properties and the properties subject to the Gulfport contribution have been prepared by Ryder Scott. Copies of the reserve reports as of December 31, 2011 prepared by Ryder Scott with respect to our properties, the Windsor UT properties and the properties subject to the Gulfport contribution are attached to this prospectus as Appendices B, C and D. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering.

 

		Pro Forma				Historical
		Year Ended December 31, 2011				Year Ended December 31,
						2011				2010				2009
Estimated proved developed reserves:
Oil (Bbls)			6,046,099				3,805,291				3,307,550				1,954,060
Natural gas (Mcf)			8,335,945				5,186,941				4,255,300				2,453,750
Natural gas liquids (Bbls)			1,969,711				1,233,319				1,105,216				591,532
Total (BOE)			9,405,134				5,903,100				5,121,983				2,954,550
Estimated proved undeveloped reserves:
Oil (Bbls)			20,140,375				12,911,576				15,511,500				27,276,880
Natural gas (Mcf)			24,261,520				14,431,924				17,407,420				25,028,070
Natural gas liquids (Bbls)			5,876,850				3,529,955				4,458,762				6,930,693
Total (BOE)			30,054,812				18,846,852				22,871,499				38,378,918
Estimated Net Proved Reserves:
Oil (Bbls)			26,186,474				16,716,867				18,819,050				29,230,940
Natural gas (Mcf)			32,597,465				19,618,865				21,662,720				27,481,820
Natural gas liquids (Bbls)			7,840,561				4,763,274				5,563,978				7,522,225
Total (BOE)(1)			39,459,946				24,749,952				27,993,481				41,333,468
Percent proved developed			23.8	%			23.9	%			18.3	%			7.1	%

 

(1)	Estimates of reserves as of December 31, 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first

 

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day of each month within the 12-month periods ended December 31, 2011, 2010 and 2009, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” beginning on page 14 of this prospectus. We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Additional information regarding our proved reserves can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates” beginning on pages 59 and 70, respectively, of this prospectus, the notes to our consolidated financial statements included elsewhere in this prospectus and the reserve reports as of December 31, 2011 included as Appendices B, C and D to this prospectus.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2011, our proved undeveloped reserves totaled 12,912 MBbls of oil, 14,432 MMcf of natural gas and 3,530 MBbls of natural gas liquids, for a total of 18,847 MBOE. On a pro forma basis after giving effect to the Contributions, at December 31, 2011 our total proved undeveloped reserves would have totaled 20,140 MBbls of oil, 24,262 MMcf of natural gas and 5,877 MBbls of natural gas liquids for a total of 30,055 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2011 were primarily due to:

 

•

Additions of 6,204 MBOE attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;

 

•

Conversion of approximately 2,223 MBOE attributable to PUDs into proved developed reserves;

 

•

Negative revisions of approximately 432 MBOE in PUDs due to revisions related to offset well performance;

 

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Exclusion of 1,447 MBOE attributable to PUD locations that were not scheduled to be drilled within the next five years; and

 

•

Movement of 6,116 MBOE from PUD to probable reserves due to changes in booking methodology used by our new independent petroleum engineers and well performance in one prospect area. The 2011 reserve report prepared by Ryder Scott assigned PUDs only in close proximity to seasoned production. The prior reports prepared by Pinnacle utilized a methodology consistent with large resource basins where geologic risk is minimal. The methodology utilized by Pinnacle typically results in a greater number of PUD locations than the “close proximity” method used by Ryder Scott. There was also a shift of 2,748 MBOE from proved to probable reserves in one prospect area where existing well performance declined more quickly than originally projected. Locations in this area were moved to the probable reserve category until more production history is obtained to confirm the economic viability of the area.

 

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Costs incurred relating to the development of PUDs were approximately $52.8 million during 2011 and approximately $80.9 million on a pro forma basis after giving effect to the Contributions as if they had occurred on January 1, 2011. Estimated future development costs relating to the development of PUDs are projected to be approximately $99.3 million in 2012, $152.4 million in 2013, $128.2 million in 2014, $105.4 million in 2015 and $84.4 million in 2016 after giving effect to the Contributions. Since our new executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2016.

As of December 31, 2011, 2% of our total proved reserves were classified as proved developed non-producing.

Oil and Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and natural gas liquids, and certain price and cost information for each of the periods indicated:

 

		Pro Forma				Historical
		Year Ended December 31, 2011				Year Ended December 31,
						2011				2010				2009
Production Data:
Oil (Bbls)			651,433				441,822				280,721				168,741
Natural gas (Mcf)			685,640				413,640				323,847				253,321
Natural gas liquids (Bbl)			151,815				86,815				79,978				70,384
Combined volumes (BOE)			917,521				597,577				414,674				281,345
Daily combined volumes (BOE/d)			2,514				1,637				1,136				771
Average Prices(1):
Oil (per Bbl)		$	92.14			$	92.26			$	76.51			$	58.01
Natural gas (per Mcf)			4.01				3.98				4.32				3.64
Natural gas liquids (per Bbl)			53.72				54.98				44.56				28.49
Combined (per BOE)			77.30				78.95				63.77				45.20
Average Costs (per BOE):
Lease operating expense		$	17.46			$	17.31			$	11.07			$	8.41
Gathering and transportation expense			0.22				0.34				0.26				0.15
Production taxes			3.97				3.91				3.25				2.36
Production taxes as a % of sales			5.1	%			4.9	%			5.1	%			5.2	%
Depreciation, depletion and amortization			29.10				25.78				19.64				11.43
General and administrative			3.97				6.03				7.36				17.99

 

(1)	After giving effect to our hedging arrangements in effect during 2009, the average prices per Bbl of oil and per BOE (on a combined basis), were $41.59 and $35.35, respectively, during that year. Average prices for our hydrocarbons were not impacted by our hedging arrangements during 2011 or 2010.

 

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Productive Wells

As of March 31, 2012, we owned an average 58.2% working interest in 177 gross (103 net) productive wells. On a pro forma basis after giving effect to the Contributions, at March 31, 2012 we would have owned an average 91.3% working interest in 181 gross (165 net) productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following table sets forth information as of March 31, 2012 relating to our leasehold acreage:

 

Developed  Acreage(1)

Undeveloped  Acreage(2)

Total Acreage

Basin

Gross(3)

Net(4)

Gross(3)

Net(4)

Gross(3)

Net(4)

Permian

7,600

4,255

45,080

25,770

52,680

30,025

 

(1)	Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

On a pro forma basis after giving effect to the Contributions, at March 31, 2012 our net developed, undeveloped and total acreage would have been 6,748, 42,955 and 49,703, respectively.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage (after giving effect to the Contributions) that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

 

		Remaining 2012								2013								2014								2015								2016
Basin		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
Permian			640				250				400				222				2,651				2,041				16,761				13,628				7,133				7,133

 

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Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

		Year ended December 31,
		2011								2010								2009
		Gross				Net				Gross				Net				Gross				Net
Development:
Productive			39				23				41				27				11				8
Dry			—				—				—				—				—				—
Exploratory:
Productive			7				4				—				—				—				—
Dry			—				—				—				—				—				—
Total:
Productive			46				27				41				27				11				8
Dry			—				—				—				—				—				—

As of December 31, 2011, we had 12 gross (6.4 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table. Since our initial acquisition in the Permian Basin through March 31, 2012, we drilled or participated in the drilling of 152 gross (81 net) wells in the Permian Basin (or 158 gross (141 net) wells after giving effect to the Contributions), of which we operate 142 gross (76 net) wells (or 147 gross (136 net) net wells after giving effect to the Contributions). Of the 158 gross wells drilled, 149 were completed as producing wells and nine are in various stages of completion.

Operations

General

We are the operator of approximately 99% of our Permian Basin acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. In March 2009, we entered into an agreement with Windsor Midstream LLC, or Midstream, an entity controlled by Wexford, our equity sponsor. During 2010 and 2011, Midstream purchased a significant portion of our oil volumes. For a description of this agreement, see “Related Party Transactions—Marketing Services” on page 120 of this prospectus. We sell all of our natural gas under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the years ended December 31, 2011 and 2010, one purchaser, Midstream, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue

 

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during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Transportation

During the initial development of our fields we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm where it is further transported by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 18.75% to 25.00%, resulting in a net revenue interest to us generally ranging from 81.25% to 75.00%.

 

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Regulation

Environmental Matters and Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.

 

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These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For

 

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example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail on page 95 in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate the emission of carbon dioxide from automobiles as an “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and

 

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local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act, first introduced in 2009, were reintroduced in the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress, would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate regulations requiring permits and implementing potential new requirements on hydraulic fracturing under the SDWA. This development could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing operations. In addition, the bills would require persons using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of their fracturing fluids to a regulatory agency, which would make the information public via the internet. Additionally, fracturing companies would be required to disclose specific chemical contents of fluids, including proprietary chemical formulas, to state authorities or to a requesting physician or nurse if deemed necessary by the physician or nurse in connection with a medical emergency.

On April 17, 2012 the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds , or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014.

 

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These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. It was signed into law on June 17, 2011, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that will apply to all wells for which the Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

 

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Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

•

the location of wells;

 

•

the method of drilling and casing wells;

 

•

the timing of construction or drilling activities, including seasonal wildlife closures;

 

•

the rates of production or “allowables”;

 

•

the surface use and restoration of properties upon which wells are drilled;

 

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the plugging and abandoning of wells; and

 

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notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas

 

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that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

 

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Operational Hazards and Insurance

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for property (including leased oil and gas properties), general liability, operational control of certain wells, pollution, commercial auto, umbrella liability, inland marine, workers compensation and other coverage. The limits for certain of our policies are as follows:

 

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oil and gas lease property: $21,888,656 with a deductible ranging from $5,000 to $20,000 based on property value;

 

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general liability: $1,000,000 per occurrence and $2,000,000 in the aggregate with a $25,000 deductible;

 

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pollution: $1,000,000 per occurrence and $2,000,000 in the aggregate with a $50,000 deductible;

 

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umbrella liability: $5,000,000 per occurrence with $5,000,000 aggregate coverage; and

 

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inland marine: limit varies on a per rig basis from $3,586,000 to $7,155,000 with a $250,000 deductible per accident.

As noted above, most of our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows.

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Employees

We have approximately 50 full time employees, including three geologists, three engineers and three land professionals, all of whom are salaried administrative or supervisory employees. Of these 50 full time employees, 31 work in our office in Midland, Texas. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

 

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Facilities

Our corporate headquarters is located in Midland, Texas. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.

Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

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MANAGEMENT

Executive Officers and Directors

Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors as of March 1, 2012.

 

Name		Age				Position
Travis D. Stice			50			Chief Executive Officer
Teresa L. Dick			42			Chief Financial Officer, Senior Vice President
Russell Pantermuehl			52			Vice President — Reservoir Engineering
Paul Molnar			56			Vice President — Geoscience
Michael Hollis			36			Vice President — Drilling
William Franklin			57			Vice President — Land
Jeff White			55			Vice President — Operations
Randall J. Holder			58			Vice President, General Counsel
Steven E. West			52			Director

Travis D. Stice—Chief Executive Officer—Mr. Stice has served as our Chief Executive Officer since January 2012. Prior to his current position with us, he served as our President and Chief Operating Officer from April 2011 to January 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc, an oil and gas exploration company, from September 2008 to September 2010. From April 2006 until August 2008, Mr. Stice served as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company. Prior to that, Mr. Stice held a series of positions at Burlington Resources, an oil and gas exploration company, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. Mr. Stice has over 26 years of industry experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 18 years of management experience. Mr. Stice graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. Mr. Stice is a registered engineer in the State of Texas, and is a 25-year member of the Society of Petroleum Engineers.

Teresa L. Dick—Chief Financial Officer, Senior Vice President—Ms. Dick has served as our Chief Financial Officer and Senior Vice President since November 2009. Prior to her current position with us, Ms. Dick served as our Corporate Controller from November 2007 until November 2009. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly-traded midstream energy master limited partnership. Ms. Dick has over 19 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. Ms. Dick is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.

Russell Pantermuehl—Vice President—Reservoir Engineering—Mr. Pantermuehl joined us in August 2011 as Vice President—Reservoir Engineering. Prior to his current position with us, Mr. Pantermuehl served as a reservoir engineering supervisor for Concho Resources Inc., an oil and gas exploration company, from March 2010 to August 2011. Mr. Pantermuehl worked for ConocoPhillips Company as a reservoir engineering advisor from January 2005 to March 2010. Mr. Pantermuehl also worked as an independent consultant in the oil and gas industry from March 2000 to December 2004. Mr. Pantermuehl received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

 

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Paul Molnar—Vice President—Geoscience—Mr. Molnar joined us in August 2011 as Vice President—Geoscience. Prior to his current position with us, Mr. Molnar served as a Senior District Geologist for Samson Investment Company, an oil and gas exploration company, from March 2011 to August 2011. Mr. Molnar worked as an asset supervisor and geosciences supervisor for ConocoPhillips Company from April 2006 to February 2011. Mr. Molnar also worked as a geologic advisor for Burlington Resources, an oil and gas exploration company, from December 1996 to March 2006. Mr. Molnar has over 31 years of industry experience. Mr. Molnar received a Master of Science degree in Geology from The State University of New York at Buffalo, New York.

Michael Hollis—Vice President—Drilling—Mr. Hollis joined us in September 2011 as Vice President—Drilling. Prior to his current position with us, Mr. Hollis served in various roles, most recently as drilling manager at Chesapeake Energy Corporation, an oil and gas exploration company, from June 2006 to September 2011. Mr. Hollis worked for ConocoPhillips Company as a senior drilling engineer from January 2004 to June 2006 and as a process engineer from 2001 to 2003. Mr. Hollis also worked as a production engineer for Burlington Resources from 1998 to 2001 as well as from June 2003 to January 2004. Mr. Hollis received his Bachelor of Science degree in Chemical Engineering from Louisiana State University.

William Franklin—Vice President—Land—Mr. Franklin joined us in August 2011 as Vice President—Land. Prior to his current position with us, Mr. Franklin worked for ConocoPhillips Company in various land management roles from May 1983 until July 2011. Mr. Franklin received a Bachelor of Arts degree in History from Oklahoma City University.

Jeff White—Vice President—Operations—Mr. White joined us in September 2011 as Vice President—Operations. Prior to his current position with us, Mr. White worked for Laredo Petroleum Holdings, Inc. as a completion manager from May 2010 to September 2011. Mr. White also worked as a staff engineer for ConocoPhillips from February 2007 to May 2009. In addition, he worked in various engineering and management positions with Anadarko Petroleum from June 1988 to June 2005. Mr. White received a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. He also received a Bachelor of Science degree in Fishery Biology from New Mexico State University.

Randall J. Holder—Vice President, General Counsel—Mr. Holder joined us in November 2011 as General Counsel and Vice President responsible for legal and human resources. Prior to his current position with us, Mr. Holder served as General Counsel and Vice President for Great White Energy Services LLC, an oilfield services company, from November 2008 to November 2011. Mr. Holder served as Executive Vice President and General Counsel for R.L. Hudson and Company, a supplier of molded rubber and plastic components, from February 2007 to October 2008. Mr. Holder was in private practice of law and a member of Holder Betz LLC from February 2005 to February 2007. Mr. Holder served as Vice President and Assistant General Counsel for Dollar Thrifty Automotive Group, a vehicle rental company, from January 2003 to February 2005 and, before that, as Vice President and General Counsel for Thrifty Rent-A-Car System, Inc., a vehicle rental company, from September 1996 to December 2002. He also served as Vice President and General Counsel for Pentastar Transportation Group, Inc. from November 1992 to September 1996, which was wholly-owned by Chrysler Corporation. Mr. Holder started his legal career with Tenneco Oil Company where he served as a Division Attorney providing legal services to the company’s mid-continent division for ten years. Mr. Holder received a Juris Doctorate degree from Oklahoma City University.

Steven E. West—Director—Mr. West has served as a director of our company since December 2011. Mr. West served as our Chief Executive Officer from January 1, 2009 to December 31, 2011. Since January 2011, Mr. West has been a partner at Wexford, focusing on Wexford’s private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, Mr. West was the chief financial officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, Mr. West worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West holds a Bachelor of Science degree in

 

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Accounting from California State University, Chico. We believe Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions qualify him to serve on our board of directors.

Our Board of Directors and Committees

Upon completion of this offering, our board of directors will consist of seven directors, at least three of whom will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Our certificate of incorporation provides that the terms of office of the directors are one year from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Our certificate of incorporation provides that the authorized number of directors will generally be not less than five nor more than thirteen, and the exact number of directors will be fixed from time to time exclusively by the board of directors pursuant to a resolution adopted by a majority of the whole board. In addition, our certificate of incorporation and our bylaws provide that, in general, vacancies on the board may be filled by a majority of directors in office, although less than a quorum.

Our board of directors will establish an audit committee in connection with this offering whose functions include the following:

 

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assist the board of directors in its oversight responsibilities regarding the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent accountant’s qualifications and independence and our accounting and financial reporting processes of and the audits of our financial statements;

 

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prepare the report required by the SEC for inclusion in our annual proxy or information statement;

 

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appoint, retain, compensate, evaluate and terminate our independent accountants;

 

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approve audit and non-audit services to be performed by the independent accountants;

 

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review and approve related party transactions; and

 

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perform such other functions as the board of directors may from time to time assign to the audit committee.

The specific functions and responsibilities of the audit committee will be set forth in the audit committee charter. Upon completion of this offering, our audit committee will include at least one director who satisfies the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Within one year after completion of the offering, we expect that our audit committee will be composed of three members that will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. We also expect that one of the members of the audit committee will qualify as an audit committee financial expert as defined under these rules and listing standards, and the other members of our audit committee will satisfy the financial literacy standards for audit committee members under these rules and listing standards.

Pursuant to our bylaws, our board of directors may, from time to time, establish other committees to facilitate the management of our business and operations. Because we are considered to be controlled by Wexford under The NASDAQ Global Market rules, we are eligible for exemptions from provisions of these rules requiring a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. We may elect to take advantage of these exemptions. In the event that we cease to be a controlled company within the meaning of these rules, we will be required to comply with these provisions after the specified transition periods.

 

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Although we will be eligible for an exemption from the compensation committee requirements under The NASDAQ Global Market rules, we intend to establish a compensation committee composed of at least two independent directors in connection with this offering. See “—Executive Compensation—Compensation Discussion and Analysis—Compensation Policy” on page 105 of this prospectus.

In connection with the Gulfport contribution, Gulfport will have the right to designate one individual as a nominee to serve on our board of directors for so long as Gulfport beneficially owns more than 10% of our outstanding common stock. Such nominee, if elected to our board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee. So long as Gulfport has the right to designate a nominee to our board and there is no Gulfport nominee actually serving as a director, Gulfport shall have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings.

Director Compensation

To date, none of our directors has received compensation for services rendered as a board member. Members of our board of directors who are also officers or employees of our company will not receive compensation for their services as directors. It is anticipated that after the completion of this offering, we will pay our non-employee directors a monthly retainer of $             and a per meeting attendance fee of $             and reimburse all ordinary and necessary expenses incurred in the conduct of our business.

In connection with this offering, we intend to implement an equity incentive plan. Under the plan, certain non-employee directors will be granted              restricted stock units, which will vest in three equal annual installments beginning on the date of grant.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee. None of our executive officers serves, or has served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.

Executive Compensation

Compensation Discussion and Analysis

Compensation Practices

Historically, our equity sponsor, Wexford, determined our overall compensation philosophy and set the compensation of our named executive officers, after taking into consideration recommendations of our then serving chief executive officer. In the case of our named executives with employment agreements, the compensation of such individuals is determined in accordance with their respective employment agreements.

Prior to the completion of this offering, our board of directors intends to establish a compensation committee comprised of at least two independent, non-employee directors and adopt a written charter for the compensation committee setting forth the compensation committee’s purpose and responsibilities. The principal responsibilities of the compensation committee will be to review and approve corporate goals and objectives relevant to the compensation of our executive officers, evaluate their performance in light of these goals and, subject to the terms of the employment agreements with our named executive officers, determine and approve our executive officers’ compensation based on such evaluation and establish policies, including with respect to the following:

 

•

the determination of the elements of executive compensation and allocation among different types of executive compensation;

 

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the determination as to when awards are granted, including awards of equity-based compensation such as restricted stock units, restricted stock and/or options;

 

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stock ownership guidelines and any policies regarding hedging the economic risk of such ownership; and

 

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•

the review of the risks and rewards associated with our compensation policies and programs.

The compensation committee will seek to provide a total compensation package designed to drive performance and reward contributions in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us. It is possible that the compensation committee will examine the compensation practices of our peer companies and may also review compensation data from the oil and natural gas industry generally to the extent the competition for executive talent is broader than a group of selected peer companies, but any decisions regarding possible benchmarking will be made following the completion of this offering. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining any changes in the compensation for our named executive officers, subject to the terms of their respective employment agreements. We expect that our Chief Executive Officer will provide periodic recommendations to the compensation committee regarding such determinations. We expect that the compensation committee will design our compensation policies and programs to encourage and reward prudent business judgment and appropriate risk taking over the long term.

Compensation Policy

Our general compensation policy is guided by several key principles:

 

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designing competitive total compensation programs to enhance our ability to attract and retain knowledgeable and experienced senior management level employees;

 

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motivating employees to deliver outstanding financial performance and meet or exceed general and specific business, operational and individual objectives;

 

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setting compensation and incentive levels relevant to the market in which the employee provides service; and

 

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providing a meaningful portion of the total compensation to our named executive officers in equity, thus assuring an alignment of interests between our senior management level employees and our stockholders.

Upon completion of this offering, our compensation committee will determine, subject to the terms of the employment agreements with our named executive officers, the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of our named executive officers. In making compensation decisions with respect to each element of compensation, the compensation committee is expected to consider numerous factors, including:

 

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the individual’s particular background and circumstances, including training and prior relevant work experience;

 

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the individual’s role with us and the compensation paid to similar persons at comparable companies;

 

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the demand for individuals with the individual’s specific expertise and experience at the time of hire;

 

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achievement of individual and company performance goals and other expectations relating to the position;

 

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comparison to other executives within our company having similar levels of expertise and experience and the uniqueness of the individual’s industry skills; and

 

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aligning the compensation of our executives with the performance of our company on both a short-term and long-term basis.

Although we expect the compensation committee to follow these policies, it is possible that the compensation committee could develop a compensation philosophy different than that discussed here.

Historic Elements of Compensation

Historically the principal elements of compensation for our named executive officers have been:

 

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base salary;

 

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bonus awards;

 

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equity awards contained in their employment agreements; and

 

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health insurance, life and disability insurance and 401(k) plan benefits available to all of our other employees.

We believe that our company does not utilize compensation policies and programs that create risks that are reasonably likely to have a material adverse impact on our company. Historically, certain management, administrative and treasury functions were provided to us by Everest, an entity controlled by Wexford, our equity sponsor. For purposes of presenting the consolidated financial statements, included elsewhere in this prospectus, allocations were made to determine the cost of general and administrative activities performed attributable to us. The allocations were made based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost. Currently, we employ all our named executive officers directly.

Components of Compensation Following the Completion of the Offering

We believe a material amount of executive compensation should be tied to our performance, and a significant portion of the total prospective compensation of each named executive officer should be tied to measurable financial and operational objectives. These objectives may include absolute performance or performance relative to a peer group. During periods when performance meets or exceeds established objectives, our named executive officers should be paid at or above targeted levels, respectively. When our performance does not meet key objectives, incentive award payments, if any, should be less than such targeted levels.

Following the completion of this offering, we anticipate that the compensation committee will seek to balance awards based on short-term annual results with awards intended to compensate our executives based on our long-term viability and success. Consequently, in addition to annual bonuses, in the future we may provide long-term incentives to our executives in the form of equity based awards to continue to align the interests of our named executive officers with those of our equity holders. These awards would be in addition to the equity awards contained in their employment agreements. In connection with this offering, our board of directors will adopt a long-term incentive plan, which we believe will further incentivize the executive officers to perform their duties in a way that will enhance our long-term success.

As discussed above, following the completion of this offering and subject to the terms of the employment agreements with our named executive officers, our compensation committee will determine the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of our named executive officers. We believe that the mix of base salary, performance-based incentive compensation, bonus awards, existing equity awards under their employment agreements, awards under the long-term incentive plan and the other benefits that are or will be available to our named executive officers will accomplish our overall compensation objectives. We believe that these elements of compensation create competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us.

Base Salary

Our named executive officers’ base salaries are determined in accordance with their respective employment agreements. We have not retained compensation consultants to advise us on compensation matters. Subject to applicable employment agreements, the compensation committee may increase base salaries to align such salaries with market levels for comparable positions in other companies in our industry if we identify significant market changes. Additionally, the compensation committee may adjust base salaries as warranted throughout the

 

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year for promotions or other changes in the scope or breadth of an executive’s role or responsibilities. The compensation committee may also evaluate our named executive officers’ salaries together with other components of their compensation to ensure that the executive’s total compensation is in line with our overall compensation philosophy. Upon completion of this offering, our named executive officers will, initially, continue to be compensated at their current annual rates, as specified in the Summary Compensation Table below.

Discretionary Annual Performance Bonus

In accordance with our named executive officers’ employment agreements, the board of directors will have the authority to award annual cash bonuses to our named executive officers that have achieved their respective performance goals determined by the board of directors for the applicable year. Pursuant to the terms of their respective employment agreements, the amount of the annual cash bonus that each of our named executive officers (with the exception of Mr. Stice) is eligible to receive is equal to 50% of such officer’s annual base salary. Mr. Stice is entitled to receive an annual bonus of at least $200,000 and may receive an annual bonus of up to $400,000 upon the achievement of performance goals to be determined by the board of directors. For 2011, our named executive officers received the annual cash bonuses set forth in the table under the caption “Summary of Compensation of Our Named Executive Officers” included beginning on page 108 of this prospectus.

Long Term Equity Incentive Compensation

We will seek to promote an ownership culture among our executive officers in an effort to enhance our long-term performance. We believe the use of stock and stock-based awards offers the best approach to achieving our compensation goals. Each of our named executive officers has been awarded an option to purchase shares of our common stock in accordance with the terms of his or her employment agreement. See “—Employment Agreements” beginning on page 110 of this prospectus. To date, we have not adopted stock ownership guidelines for our executives. In connection with this offering, we intend to implement an equity incentive plan. The purpose of this plan will be to continue to enable us, and our affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our long term success and to provide incentives that will be linked directly to increases in share value that will inure to the benefit of our stockholders. The plan will provide a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of equity awards. The terms of our equity incentive plan are described in more detail following the Summary Compensation Table.

Other Compensation and Perquisites

Consistent with our compensation philosophy, we anticipate that our compensation committee will continue to provide benefits to our executives that are substantially the same as those currently being offered to our other employees, including health insurance, life and disability insurance and a 401(k) plan. The benefits and perquisites that may be available to our executive officers in addition to those available to our other employees include a car allowance and club dues.

Tax Implications of Executive Compensation Policy

Under Section 162(m) of the Internal Revenue Code, a public company generally may not deduct compensation in excess of $1.0 million per year per person paid to its principal executive officer, principal financial officer and the three other most highly compensated executive officers whose compensation is disclosed in its proxy statement as a result of their total compensation, subject to certain exceptions. Qualifying performance-based compensation will not be subject to the deduction limit if certain requirements are met. Although our long-term and incentive compensation plans and agreements have provisions that are intended to satisfy the performance-based compensation exception to the Section 162(m) deduction limit, regulations under Section 162(m) also provide a transition reliance period in the case of a corporation that is not publicly held and

 

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becomes publicly held in connection with an initial public offering. During the reliance period, the deduction limit of Section 162(m) does not apply to any compensation paid pursuant to a plan or agreement that existed during the period that the corporation was not publicly held, provided the prospectus accompanying the initial public offering discloses information concerning the plans or agreements in accordance with applicable securities laws. The reliance period ends on the earliest of (1) the expiration of the plan or agreement; (2) the material modification of the plan or agreement; (3) the issuance of all employer stock or compensation reserved under the plan; or (4) the first meeting of stockholders at which directors are elected that occurs after the close of the third calendar year following the calendar year in which the initial public offering occurs.

We anticipate that our compensation committee will structure our long-term and incentive compensation programs to preserve the tax deductibility of compensation paid to our executive officers. However, our compensation committee will have the authority to award performance-based compensation that is not deductible and we cannot guarantee that it will only award deductible compensation to our executive officers. In addition, notwithstanding our compensation committee’s efforts, ambiguities and uncertainties regarding the application and interpretation of Section 162(m) make it impossible to provide assurance that any performance based compensation will, in fact, satisfy the requirements for deductibility under Section 162(m). Time vested restricted stock awards will not be treated as performance based compensation and, as a result, the deductibility of such awards could be limited. Also, base salaries and other non-performance based compensation as defined in Section 162(m) in excess of $1.0 million paid to these executive officers in any year would not qualify for deductibility under Section 162(m).

Summary of Compensation for Our Named Executive Officers

The following table shows the compensation of all individuals serving as our principal executive officer and principal financial officer during 2011 and of our next most highly compensated executive officer serving as of December 31, 2011, whose total compensation exceeded $100,000 for the fiscal year ended December 31, 2011.

 

		Year				Salary				Bonus(1)				Option Awards(2)				All Other Compensation(3)				Total
Steven E. West(4)			2011			$	—			$	—			$	—			$	—			$	—
Former Chief Executive Officer
Travis D. Stice(5)			2011			$	115,879			$	225,000			$				$	5,874			$
Current Chief Executive Officer; Former President and Chief Operating Officer
Teresa L. Dick			2011			$	98,517			$	112,631			$				$	3,558			$
Chief Financial Officer, Senior Vice President
Jeff White			2011			$	55,846			$	131,820			$				$	309			$
Vice President — Operations

 

(1)	Mr. Stice received a $225,000 annual incentive bonus, Ms. Dick received a $46,820 retention bonus and a $65,811 annual incentive bonus and Mr. White received an $85,000 signing bonus and a $27,500 annual incentive bonus.

(2)

Reflects the amount recognized for financial reporting purposes in 2011 under FASB ASC Topic 718 for the option award granted to each named executive officer under his or her employment agreement with us. The amount was calculated using certain assumptions set forth in Note 8 to our historical financial statements included in this prospectus.

(3)

Amounts for Mr. Stice include our 401(k) plan contributions of $1,832, car allowance of $3,665 and life insurance premium payments of $377. Amounts for Ms. Dick include our 401(k) plan contributions of $2,735 and life insurance premium payments of $823. Amounts for Mr. White include life insurance premium payments of $309.

 

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(4)	Mr. West resigned as our chief executive officer in December 2011. Mr. West did not receive any compensation from us in 2011.

(5)	Mr. Stice became our President and Chief Operating Officer in April 2011. On January 1, 2012, Mr. Stice resigned as President and Chief Operating Officer and became our Chief Executive Officer. Mr. Stice’s annual base salary remains at $300,000.

2011 Grants of Plan-Based Awards

The following table presents information regarding each grant of an award made to our named executive officers in 2011 under any Company plan.

 

Name		Grant Date				All Other Option Awards: Number of Securities Underlying Options (#)(1)				Exercise or Base Price of Option Awards ($/Sh)(2)				Grant Date Fair Value of Stock and Option Awards ($)(3)
Steve E. West			—				—				—
Travis D. Stice			4/18/2011				1.00	%		$	3,600,000
Teresa L. Dick			9/1/2011				0.25	%		$	900,000
Jeff White			9/30/2011				0.50	%		$	2,500,000

 

(1)

All option awards shown represent an option to acquire a membership interest percentage in Windsor Permian. Upon the contribution to us of all the outstanding equity interests in Windsor Permian prior to the closing of this offering, an option to acquire shares of our common stock will be substituted for the option to acquire membership interests in Windsor Permian. Assuming the sale by us of              shares of common stock in this offering at an estimated initial public offering price of $             per share, each of Mr. Stice’s, Ms. Dick’s and Mr. White’s, options will be substituted for an option to acquire             ,              and              shares of our common stock, respectively.

(2)	The exercise price shown represents the aggregate exercise price for the option to acquire the entire membership interest percentage in Windsor Permian.

(3)

Grant date fair value of the option award granted to each named executive officer in 2011 is computed in accordance with FASB ASC Topic 718 and reflects the total amount of the award to be spread over the applicable vesting period. Each named executive officer’s option award vests as described in such named executive officer’s employment agreement under “—Employment Agreements” below beginning on page 110.

2011 Outstanding Equity Awards at Year-End Table

The following table presents, for each of the named executive officers, information regarding outstanding equity awards held as of December 31, 2011.

 

		Option Awards
Name		Number of Securities Underlying Unexercised Options (#) Exercisable				Number of Securities Underlying Unexercised Options (#) Unexercisable(1)				Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)				Option Exercise Price  ($)(2)				Option Expiration Date
Steven E. West			—				—				—				—				—
Travis D. Stice			—				1.00	%			—			$	3,600,000				4/18/2016
Teresa L. Dick			—				0.25	%			—			$	900,000				9/1/2016
Jeff White			—				0.50	%			—			$	2,500,000				9/30/2016

 

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(1)

All option awards shown represent an option to acquire a membership interest percentage in Windsor Permian. Upon the contribution to us of all the outstanding equity interests in Windsor Permian prior to the closing of this offering, an option to acquire shares of our common stock will be substituted for the option to acquire membership interests in Windsor Permian. Assuming the sale by us of              shares of common stock in this offering at an estimated initial public offering price of $             per share, each of Mr. Stice’s, Ms. Dick’s and Mr. White’s options will be substituted for an option to acquire             ,              and              shares of our common stock, respectively.

(2)	The exercise price shown represents the aggregate exercise price for the option to acquire the entire membership interest percentage in Windsor Permian.

Employment Agreements

The following summarizes the material terms of the employment agreements we have with our named executive officers.

Travis D. Stice. Effective April 2011, we entered into an employment agreement with Mr. Stice, our Chief Executive Officer. The employment agreement has a three-year term and provides for an annual base salary of $300,000. Mr. Stice is also entitled to receive an annual bonus of at least $200,000, which could be increased up to $400,000 depending upon his achievement of certain performance goals as determined by our board of directors. Mr. Stice is entitled to participate in such life and medical insurance plans and other similar plans that we establish from time to time for our executive employees, and is paid a $900 monthly vehicle allowance. Pursuant to the terms of his employment agreement, Mr. Stice has an option to acquire a 1.0% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $3.6 million, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Mr. Stice’s employment agreement and will be exercisable for five years from the effective date of his employment agreement or until his earlier termination. Upon the contribution of the Windsor Permian LLC membership interests to us in connection with the closing of this offering, an option to acquire shares of our common stock will be substituted for the original option to acquire membership interests in Windsor Permian LLC. The substituted option will be for such number of shares and with such exercise price as shall preserve the economic value of the original option in compliance with applicable tax requirements. The vesting schedule and exercise rights will remain the same. Mr. Stice has agreed to certain restrictive covenants in his employment agreement, including, without limitation, his agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Mr. Stice’s affiliation with us and for a period of six months thereafter. Mr. Stice’s continued employment with us is “at-will,” meaning that either we or Mr. Stice may terminate the employment relationship at any time and for any reason, with or without notice. However, if we terminate Mr. Stice’s employment without “cause,” we will be obligated to continue paying Mr. Stice’s annual base salary until the expiration of the term of his employment agreement and pay a prorated portion of Mr. Stice’s minimum annual bonus for the period prior to termination, subject to Mr. Stice’s compliance with the restrictive covenants discussed above and his execution of a full general release in our favor. If Mr. Stice’s employment is terminated due to death or disability, our sole obligation, subject to Mr. Stice’s compliance with the restrictive covenants discussed above, will be to pay any earned but unpaid base salary and a prorated portion of Mr. Stice’s minimum annual bonus for the period prior to termination. In the event Mr. Stice’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option described above effective as of the termination date. For purposes of Mr. Stice’s employment agreement, “cause” is generally defined as Mr. Stice’s (a) willful and knowing refusal or failure to perform his duties in any material respect, (b) willful misconduct or gross negligence in performing his duties, (c) material breach of his employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition or (g) failure to comply with directives of our board of directors. In addition, in the event that more than 50% of the combined voting power of

 

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our then outstanding stock is controlled by one or more parties that is not Wexford or an affiliate of Wexford, the options described above will vest immediately. The benefits Mr. Stice is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 115 of this prospectus.

Teresa L. Dick. Effective September 2011, we entered into an employment agreement with Ms. Dick, our Senior Vice President and Chief Financial Officer. The employment agreement has a one-year term and provides for an annual base salary of $250,000. Subject to Ms. Dick’s achievement of certain performance goals as determined by our board of directors for each fiscal year, Ms. Dick is entitled to an annual bonus of 50% of her annual base salary. Ms. Dick is also entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Pursuant to the terms of her employment agreement, Ms. Dick has an option to acquire a 0.25% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $900,000, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Ms. Dick’s employment agreement and will be exercisable for five years from the effective date of such employment agreement or until her earlier termination (except for termination upon death, disability or by us without cause). Upon the contribution of the Windsor Permian LLC membership interests to us in connection with the closing of this offering, an option to acquire shares of our common stock will be substituted for the original option to acquire membership interests in Windsor Permian LLC. The substituted option will be for such number of shares and with such exercise price as shall preserve the economic value of the original option in compliance with applicable tax requirements. The vesting schedule and exercise rights will remain the same. Ms. Dick has agreed to certain restrictive covenants in her employment agreement, including, without limitation, her agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Ms. Dick’s affiliation with us and for a period of six months thereafter. Ms. Dick’s continued employment with us is “at-will,” meaning that either we or Ms. Dick may terminate the employment relationship at any time and for any reason, with or without notice. However, if (i) we terminate Ms. Dick’s employment without “cause,” (ii) Ms. Dick resigns for good reason, meaning such resignation follows a material uncured breach by us of the employment agreement or a material diminution in Ms. Dick’s position, duties or authority, or (iii) Ms. Dick’s employment is terminated due to death or disability, then we will be obligated to continue paying Ms. Dick’s base annual salary until the expiration of the term of her employment agreement and, in the case of termination without cause or upon death or disability, to honor our obligations with respect to the option described above; provided, in each case, that Ms. Dick continues to comply with the restrictive covenants described above and (except in the case of clause (iii) above) executes a full general release in our favor. In the event Ms. Dick’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option described above effective as of the termination date. For purposes of Ms. Dick’s employment agreement, “cause” is generally defined as Ms. Dick’s (a) willful and knowing refusal or failure to perform her duties in any material respect, (b) willful misconduct or gross negligence in performing her duties, (c) material breach of her employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition, (g) dishonesty in connection with her responsibilities as an employee or (h) failure to comply with directives of our board of directors. In addition, (x) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and there is a material change in Ms. Dick’s position, duties or authority or (y) upon termination without cause or due to death or disability, the options described above will vest immediately. The benefits Ms. Dick is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 115 of this prospectus.

 

 

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Jeff White. Effective September 2011, we entered into an employment agreement with Mr. White, our Vice President—Operations. The employment agreement has a three-year term and provides for an annual base salary of $220,000. Subject to Mr. White’s achievement of certain performance goals as determined by our board of directors for each fiscal year, Mr. White is entitled to an annual bonus of 50% of his annual base salary. Upon entering into the employment agreement, Mr. White received an $85,000 signing bonus and, if this offering is completed within one year of Mr. White’s hiring, he will be entitled to receive shares of our common stock with a value equal to $170,000. If we do not complete this offering within one year of his hiring, Mr. White will receive a $170,000 cash bonus. Mr. White is also entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Pursuant to the terms of his employment agreement, Mr. White has an option to acquire a 0.5% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $2.5 million, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Mr. White’s employment agreement and will be exercisable for five years from the effective date of his employment agreement or until his earlier termination (except for termination upon death, disability or by us without cause). Upon the contribution of the Windsor Permian LLC membership interests to us in connection with the closing of this offering, an option to acquire shares of our common stock will be substituted for the original option to acquire membership interests in Windsor Permian LLC. The substituted option will be for such number of shares and with such exercise price as shall preserve the economic value of the original option in compliance with applicable tax requirements. The vesting schedule and exercise rights will remain the same. Mr. White has agreed to certain restrictive covenants in his employment agreement, including, without limitation, his agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Mr. White’s affiliation with us and for a period of six months thereafter. Mr. White’s continued employment with us is “at-will,” meaning that either we or Mr. White may terminate the employment relationship at any time and for any reason, with or without notice. However, if (i) we terminate Mr. White’s employment without “cause,” (ii) Mr. White resigns for good reason, meaning such resignation follows a material uncured breach by us of the employment agreement or a material diminution in Mr. White’s position, duties or authority, or (iii) Mr. White’s employment is terminated due to death or disability, then we will be obligated to continue paying Mr. White’s base annual salary until the expiration of the term of his employment agreement and, in the case of termination without cause or upon death or disability, to honor our obligations with respect to the option described above; provided, in each case, that Mr. White continues to comply with the restrictive covenants described above and (except in the case of clause (iii) above) executes a full general release in our favor. In the event Mr. White’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option described above effective as of the termination date. For purposes of Mr. White’s employment agreement, “cause” is generally defined as Mr. White’s (a) willful and knowing refusal or failure to perform his duties in any material respect, (b) willful misconduct or gross negligence in performing his duties, (c) material breach of his employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition, (g) dishonesty in connection with his responsibilities as an employee or (h) failure to comply with directives of our board of directors. In addition, (x) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and there is either a material change in Mr. White’s position, duties or authority or Mr. White is required to move outside a 50 mile radius of Midland, Texas or (y) upon termination without cause or due to death or disability, the options described above will vest immediately. The benefits Mr. White is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 115 of this prospectus.

 

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Equity Incentive Plan

Prior to the completion of this offering, we did not have any stock option or other equity incentive plan except for the equity awards granted in the employment agreements with our named executive officers and, except for such awards, there are no stock options, restricted stock units or other equity awards outstanding for any of our named executive officers. Prior to this offering, we intend to implement our equity incentive plan.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed              shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure. To the extent that an award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code, then the maximum number of shares of common stock issuable in the form of each type of award under our equity incentive plan to any one participant during a calendar year shall not exceed              shares. Additionally, no participant shall receive in excess of the aggregate amount of              shares pursuant to all awards issued under our equity incentive plan during any calendar year.

We anticipate granting options and restricted stock units to employees and certain non-employee directors under the plan upon completion of this offering in the amount to be determined by the compensation committee.

Share Reserve. The aggregate number of shares of common stock initially authorized for issuance under the plan is              shares. However, (i) shares covered by an award that expires or otherwise terminates without having been exercised in full and (ii) shares that are forfeited to, or repurchased by, us pursuant to a forfeiture or repurchase provision under the plan may return to the plan and be available for issuance in connection with a future award.

Administration. Our board of directors (or our compensation committee or any other committee of the board of directors as may be appointed by our board of directors from time to time) administers the plan. Among other responsibilities, the plan administrator selects participants from among the eligible individuals, determines the number of shares that will be subject to each award and determines the terms and conditions of each award, including methods of payment, vesting schedules and limitations and restrictions on awards. The plan administrator may amend, suspend, or terminate the plan at any time. Amendments will not be effective without stockholder approval if stockholder approval is required by applicable law or stock exchange requirements. Unless terminated earlier, our equity incentive plan will terminate in                     , 2022.

Stock Options. Incentive and nonstatutory stock options are granted pursuant to incentive and nonstatutory stock option agreements. Employees, directors and consultants may be granted nonstatutory stock options, but only employees may be granted incentive stock options. The plan administrator determines the exercise price of a stock option, provided that the exercise price of a stock option generally cannot be less than 100% (and in the case of an incentive stock option granted to a more than 10% stockholder, 110%) of the fair market value of our common stock on the date of grant, except when assuming or substituting options in limited situations such as an acquisition. Generally, options granted under the plan vest ratably over a five-year period and have a term of ten years (five years in the case of an incentive stock option granted to a more than 10% stockholder), unless specified otherwise by the plan administrator in the option agreement.

Acceptable consideration for the purchase of common stock issued upon the exercise of a stock option will be determined by the plan administrator and may include (i) cash or check, (ii) a broker-assisted cashless exercise, (iii) the tender of common stock previously owned by the optionee, (iv) stock withholding and (v) other legal consideration approved by the plan administrator, such as exercise with a full recourse promissory note (not applicable for directors and executive officers).

 

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Unless the plan administrator provides otherwise (solely with respect to intervivos transfers to certain family members and estate planning vehicles), nonstatutory options generally are not transferable except by will or the laws of descent and distribution. An optionee may designate a beneficiary, however, who may exercise the option following the optionee’s death. Incentive stock options are not transferable except by will or the laws of descent and distribution.

Restricted Awards. Restricted awards are awards of either actual shares of common stock (e.g., restricted stock awards), or of hypothetical share units (e.g., restricted stock units) having a value equal to the fair market value of an identical number of shares of common stock, that will be settled in the form of shares of common stock upon vesting or other specified payment date, and which may provide that such restricted awards may not be sold, transferred, or otherwise disposed of for such period as the plan administrator determines. The purchase price and vesting schedule, if applicable, of restricted awards are determined by the plan administrator. A restricted stock unit is similar to a restricted stock award except that participants holding restricted stock units do not have any stockholder rights until the stock unit is settled with shares. Stock units represent an unfunded and unsecured obligation for us and a holder of a stock unit has no rights other than those of a general creditor.

Performance Awards. Performance awards entitle the recipient to vest in or acquire shares of common stock, or hypothetical share units having a value equal to the fair market value of an identical number of shares of common stock that will be settled in the form of shares of common stock upon the attainment of specified performance goals. Performance awards may be granted independent of or in connection with the granting of any other award under the plan. Performance goals will be established by the plan administrator based on one or more business criteria that apply to the plan participant, a business unit, or our company and our affiliates. Performance goals will be objective and will be intended to meet the requirements of Section 162(m) of the Code. Performance goals must be determined prior to the time 25% of the service period has elapsed but not later than 90 days after the beginning of the service period. No payout will be made on a performance award granted to a named executive officer unless all applicable performance goals and service requirements are achieved. Performance awards may not be sold, assigned, transferred, pledged or otherwise encumbered and terminate upon the termination of the participant’s service to us or our affiliates.

Stock Appreciation Rights. Stock appreciation rights may be granted independent of or in tandem with the granting of any option under the plan. Stock appreciation rights are granted pursuant to stock appreciation rights agreements. The exercise price of a stock appreciation right granted independent of an option is determined by the plan administrator, but as a general rule will be no less than 100% of the fair market value of our common stock on the date of grant. The exercise price of a stock appreciation right granted in tandem with an option is the same as the exercise price of the related option. Upon the exercise of a stock appreciation right, we will pay the participant an amount equal to the product of (i) the excess of the per share fair market value of our common stock on the date of exercise over the strike price, multiplied by (ii) the number of shares of common stock with respect to which the stock appreciation right is exercised. Payment will be made in cash, delivery of stock, or a combination of cash and stock as deemed appropriate by the plan administrator.

Adjustments in capitalization. In the event that there is a specified type of change in our common stock without the receipt of consideration by us, such as pursuant to a merger, consolidation, reorganization, recapitalization, reincorporation, stock dividend, dividend in property other than cash, stock split, liquidating dividend, combination of shares, exchange of shares, change in corporate structure or other transaction, appropriate adjustments will be made to the various limits under, and the share terms of, the plan including (i) the number and class of shares reserved under the plan, (ii) the maximum number of stock options and stock appreciation rights that can be granted to any one person in a calendar year and (iii) the number and class of shares and exercise price, strike price, or purchase price, if applicable, of all outstanding stock awards.

Corporate Transactions. In the event of a change in control transaction (other than a transaction resulting in Wexford or an entity controlled by, or under common control with Wexford maintaining direct or indirect control over the Company), or a corporate transaction such as a dissolution or liquidation of our company, or any

 

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corporate separation or division, including, but not limited to, a split-up, a split-off or a spin-off, or a sale in one or a series of related transactions, of all or substantially all of the assets of our company or a merger, consolidation, or reverse merger in which we are not the surviving entity, then all outstanding stock awards under the plan may be assumed, continued or substituted for by any surviving or acquiring entity (or its parent company), or may be cancelled either with or without consideration for the vested portion of the awards, all as determined by the plan administrator. In the event an award would be cancelled without consideration paid to the extent vested, the award recipient may exercise the award in full or in part for a period of ten days.

401(k) Plan

We participate in a 401(k) Plan. Employees may elect to defer a portion of their compensation up to the statutorily prescribed limit. Each pay period we make a matching contribution to each employee’s deferral, not to exceed six percent. An employee’s interests in his or her deferrals are 100% vested when contributed. An employee’s interests in the matching contribution are vested at the rate of 20% for each completed year of eligibility. The 401(k) Plan is intended to qualify under Section 401(a) of the Internal Revenue Code. As such, contributions to the 401(k) Plan and earnings on those contributions are not taxable to the employee until distributed from the 401(k) Plan, and all contributions are deductible by us when made.

Potential Payments Upon Termination, Resignation or Change of Control

The following table shows the estimated benefits payable to our named executive officers in various hypothetical scenarios as of December 31, 2011:

 

		Termination Without Cause or Upon Death or Disability(1)(2)																Resignation for Good Reason(3)																Change of Control
Name		Base Salary				Benefits				Options				Total				Base Salary				Benefits				Options				Total				Base Salary				Benefits				Options				Total
Steven West			—				—				—				—				—				—				—				—				—				—				—				—
Travis D. Stice(4)		$	688,767	(6)			—				—			$	688,767	(6)							—				—								—				—
Teresa L. Dick(5)		$	186,986	(7)			—							$	186,986	(7)							—				—								—				—
Jeff White(5)		$	659,507	(8)			—							$	659,507	(8)							—				—								—				—

 

(1)

In the event a named executive officer (except for Mr. West) is terminated upon death or disability, the receipt of the payments and benefits described in this table is subject to such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement.

(2)

In the event a named executive officer is terminated without cause, the receipt of the payments and benefits described in this table are subject to (a) such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement and (b) such executive executing (and not revoking) a full general release of all claims, known or unknown against us, Wexford and various other parties affiliated with Wexford.

(3)

Under the terms of the employment agreements with our named executive officers (except for Mr. Stice), the applicable officer is entitled to certain benefits in the event such officer resigns for good cause, which means such resignation follows any (a) material breach by us of the terms of the applicable employment agreement or (b) material diminution in the officer’s position, duties or authority which in either case is not cured within thirty (30) business days following our receipt of notice thereof, subject to (i) such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement and (ii) such executive executing (and not revoking) a full general release of all claims, known or unknown against us, Wexford and various other parties affiliated with Wexford.

 

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(4)

Under the terms of Mr. Stice’s employment agreement, Mr. Stice’s stock options granted pursuant to such agreement shall vest immediately in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not us, Wexford or an affiliate of Wexford.

(5)

Under the terms of our employment agreement with each of Ms. Dick and Mr. White the stock options granted under such agreement will vest immediately (a) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not us, Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and either there is a material change in the applicable named executive officer’s position, duties or authority or such officer is required to relocate to a location outside of a 50 mile radius of Midland, Texas or (b) upon termination without cause or upon death or disability.

(6)	Represents the amount payable under Mr. Stice’s employment agreement and is equal to Mr. Stice’s base salary for the remainder of the term of his employment agreement, which expires on April 18, 2014.

(7)	Represents the amount payable under Ms. Dick’s employment agreement and is equal to Mr. Dick’s base salary for the remainder of the term of her employment agreement, which expires on September 30, 2012.

(8)	Represents the amount payable under Mr. White’s employment agreement and is equal to Mr. White’s base salary for the remainder of the term of his employment agreement, which expires on September 30, 2014.

Limitations on Liability and Indemnification of Officers and Directors

Certificate of Incorporation and Bylaws

Our certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the Delaware General Corporation Law, or DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by the DGCL:

 

•

for any breach of the director’s duty of loyalty to the company or its stockholders;

 

•

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

•

in respect of certain unlawful dividend payments or stock redemptions or repurchases; and

 

•

for any transaction from which the director derives an improper personal benefit.

This provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

Our certificate of incorporation also provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service.

Our bylaws include provisions relating to advancement of expenses and indemnification rights consistent with those provided in our certificate of incorporation. In addition, our bylaws provide:

 

•

for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time; and

 

•

permit us to purchase and maintain insurance, at our expense, to protect us and any of our directors, officers and employees against any loss, whether or not we would have the power to indemnify that person against that loss under Delaware law.

 

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Indemnification Agreements

We will enter into indemnification agreements with each of our current directors and executive officers effective upon the closing of this offering. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Liability Insurance

We intend to provide liability insurance for our directors and officers, including coverage for public securities matters. There is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.

 

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RELATED PARTY TRANSACTIONS

Review and Approval of Related Party Transactions

We do not currently have a written policy regarding the review and approval of related party transactions, but intend to implement such a policy in connection with, and prior to the completion of, this offering. In connection with this offering, we will establish an audit committee consisting solely of independent directors whose functions will be set forth in the audit committee charter. We anticipate that one of the audit committee’s functions will be to review and approve all relationships and transactions in which we and our directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their immediate family members, have a direct or indirect material interest. We anticipate that such policy will be a written policy included as part the audit committee charter that will be implemented by the audit committee and in the Code of Business Conduct and Ethics that our board of directors will adopt prior to the completion of this offering.

Historically, the review and approval of related party transactions have been the responsibility of our management, and all of the transactions discussed under “Related Party Transactions” below have been approved by our management, subject to a conflicts of interest policy set forth in our employee handbook, pursuant to which all of our employees must avoid any situations where their personal outside interest could conflict, or even appear to conflict, with the interests of the Company. Although our management believes that the terms of the related party transactions described below are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties.

Our management will continue to review and approve related party transactions, subject to the above-referenced conflicts of interest policy, until the adoption of the policy regarding the review and approval of such transactions by the audit committee, which we intend to adopt in connection with, and prior to the completion of, this offering.

Gulfport Contribution and Investor Rights Agreement

On May 7, 2012, we entered into a contribution agreement with Gulfport in which Gulfport agreed to contribute to us, prior to the closing of this offering, all of its oil and natural gas interests in the Permian Basin in exchange for (i) shares of our common stock representing 35% of our common stock outstanding immediately prior to the closing of this offering and (ii) approximately $63.6 million in the form of a non-interest bearing promissory note that will be repaid in full upon the closing of this offering with a portion of the net proceeds from this offering. The aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment based on changes in our working capital, long-term debt and certain other items identified in the contribution agreement as of the date of the contribution. Gulfport’s obligation to make this contribution is contingent upon, among other things, the contribution to us of all the outstanding equity interests in Windsor Permian and Gulfport’s satisfaction with the terms of this offering. Under the contribution agreement, Gulfport is generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the contribution and we are responsible for such liabilities and obligations arising after the contribution. At the closing of the Gulfport contribution, we will enter into an investor rights agreement with Gulfport in which Gulfport will be granted certain (i) demand and “piggyback” registration rights, (ii) director nomination rights and (iii) information rights. For additional information regarding the terms of the contribution agreement and the investor rights agreement, see “Prospectus Summary—The Contributions,” “Management—Our Board of Directors and Committees” and “Shares Eligible for Future Sale—Registration Rights” beginning on pages 6, 103 and 128, respectively, of this prospectus. Mike Liddell, who served as the Operating Member and Chairman of Windsor Permian prior to the completion of this offering, is also the Chairman of the Board and a director of Gulfport and has an interest in DB Holdings. Charles E. Davidson, the Chairman and Chief Investment Officer of Wexford, beneficially owned approximately 9.5% of Gulfport’s outstanding common stock as of March 13, 2012.

 

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Administrative Services

We are a party to a shared services agreement, dated March 1, 2008, with Everest Operations Management LLC (formerly, Windsor Energy Resources LLC), or Everest, an entity controlled by Wexford, our equity sponsor. Under this agreement, Everest provides us with technical, administrative and payroll services and office space in Oklahoma City, Oklahoma and we reimburse Everest in an amount determined by Everest’s management based on estimates of the amount of office space provided and the amount of its employees’ time spent performing services for us. Historically, certain management, administrative, employee and treasury functions and office space were provided to us by Everest. For purposes of presenting the consolidated financial statements, included elsewhere in this prospectus, allocations were made to determine the cost of general and administrative activities performed attributable to us. The allocations were made based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost.

The initial term of the shared services agreement with Everest was two years. Since the expiration of such two-year period on March 1, 2010, the agreement, by its terms, has continued on a month-to-month basis and

will continue to do so until terminated by either party upon thirty days prior written notice. For the years ended December 31, 2011, 2010 and 2009, we incurred total costs to Everest of approximately $10.0 million, $8.0 million and $5.5 million, respectively, and at December 31, 2011, 2010 and 2009, we owed $0.8 million, $0.4 million and $0.9 million, respectively, under this shared services agreement. We expect to discontinue all services under this shared services agreement prior to the closing of this offering.

Wexford Contribution

The historical financial and operating information included in this prospectus pertains to the assets, liabilities, revenues and expenses of Windsor Permian. Prior to the completion of this offering, Wexford will cause DB Holdings to contribute all of the outstanding equity interests in Windsor Permian to us in exchange for shares of our common stock and Windsor Permian will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. For additional information regarding this contribution by Wexford, see “Prospectus Summary—Our History” on page 8 of this prospectus.

Drilling Services

Bison Drilling and Field Services LLC, or Bison, has performed drilling and field services for us under master drilling agreements. Under our most recent master drilling agreement with Bison, effective as of January 1, 2012, Bison committed to accept orders from us for the use of at least two of its rigs, and is currently providing drilling services to us using four of its rigs. This master drilling agreement is terminable by either party on 30 day’s prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. Bison was a wholly-owned subsidiary of Windsor Permian until March 31, 2011, when various entities controlled by Wexford started contributing capital to Bison. These contributions aggregated $11.5 million and ultimately diluted Windsor Permian’s ownership interest to 52.2%. In September 2011, Windsor Permian sold a 25% interest in Bison to Gulfport for $6.0 million, subject to adjustment. At the time of the transaction, an affiliate of Wexford beneficially owned approximately 13.3% of Gulfport’s common stock, but that ownership is now less than 10%. In April 2012, Gulfport increased its ownership interest in Bison to 40%. As a result of these transactions, Windsor Permian’s ownership interest in Bison was reduced to 22%, with the remaining equity interests in Bison held by Gulfport and various entities controlled by Wexford. Prior to its contribution to us, Windsor Permian will distribute its remaining interest in Bison to its member. As a result, we will not own any interest in Bison when all the outstanding equity interests in Windsor Permian are contributed to us prior to the completion of this offering. For the period April 1, 2011 through December 31, 2011, we were billed $16.3 million by Bison for drilling services. At December 31, 2011, we had a payable due to Bison of $0.2 million.

 

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Completion and Well Servicing Services

We contracted with Great White Energy Services, or Great White, an entity formerly controlled by Wexford, for certain well completion services. For the year ended December 31, 2010 and 2009, we were billed $7.7 million and $3.3 million by Great White, and we owed $3.1 million for such services at December 31, 2010 and no amounts at December 31, 2009. Effective August 24, 2011, Great White was sold to an unrelated third party and, therefore, Great White is no longer a related party. While still a related party, during the year ended December 31, 2011 Great White billed us $12.5 million for such services.

Marketing Services

On March 1, 2009, we entered into an agreement with Windsor Midstream LLC, or Midstream, an entity controlled by Wexford, pursuant to which Midstream purchased a significant portion of our oil volumes. For the years ended December 31, 2011, 2010 and 2009, our revenues from Midstream were $38.2 million, $21.4 million and $8.8 million, respectively, and at December 31, 2011, 2010 and 2009 we had an accounts receivable balance of $4.1 million, $2.7 million and $1.5 million, respectively. Effective December 1, 2011, we ceased all sales of our oil production to Midstream under this agreement.

Midland Lease

We occupy our corporate headquarters in Midland, Texas under a five-year lease, effective May 15, 2011, with Fasken Midland, LLC, or Fasken, an entity controlled by an affiliate of Wexford. Through December 31, 2011, we paid $40,080 to Fasken under this lease. Our current monthly rent under the lease is $7,593, which amount will increase approximately 4% annually on June 1 of each year during the remainder of the lease term.

Area of Mutual Interest and Related Agreements

Effective as of November 1, 2007, we and Gulfport entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. The agreement continues in force on a month-to-month basis until terminated by either party upon 30 days prior written notice.

In connection with the area of mutual interest agreement, we, Gulfport and Windsor Energy Group, L.L.C., or Energy Group, an entity controlled by Wexford, as the operator, entered into a joint development agreement, effective as of November 1, 2007, pursuant to which we and Gulfport agreed to develop certain jointly-held oil and gas leases in the Permian Basin and Energy Group agreed to act as the operator under the terms of a joint operating agreement, effective as of November 1, 2007. In the event either party has a majority interest in a prospect (as defined in the development agreement), the majority party may designate the operator of its choice. The parties agreed to designate Energy Group as the operator with respect to the contract area as provided in the joint operating agreement. As operator of these properties, Energy Group was responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which we held an interest. Effective February 26, 2010, the agreement with Energy Group was terminated and we became the operator of these properties. As of December 31, 2011 we did not owe Energy Group any amounts. For the years ended December 31, 2010 and 2009, Energy Group billed us approximately $3.8 million and $20.4 million, respectively, and at December 31, 2010 and 2009, we owed $0.07 million and $2.8 million, respectively, for these services.

Upon becoming operator effective February 26, 2010, we began providing joint interest billing services to certain of our affiliates. For the years ended December 31, 2011 and 2010, we billed Gulfport $56.7 million and $32.4 million, respectively, and we billed an entity controlled by Wexford $5.3 million and $8.8 million, respectively, for such services. At December 31, 2011 and 2010, Gulfport owed us $4.5 million and $4.6 million, respectively, and the Wexford controlled entity owed us $0.4 million and zero, respectively.

 

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Our area of mutual interest agreement and joint development agreement, each with Gulfport, will be terminated upon the Gulfport contribution.

Investment in Muskie Holdings LLC

During 2011, Windsor Permian purchased certain assets, real estate and rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture grade sand for $4.1 million from an unrelated third party. On October 7, 2011, Windsor Permian contributed these assets, real estate and lease rights to a newly-formed entity, Muskie Holdings LLC, or Muskie, in exchange for a 48.6% equity interest. The remaining equity interests in Muskie are held 25% by Gulfport and 26.4% by entities controlled by Wexford. Through additional contributions from the Wexford-controlled entities to Muskie, Windsor Permian’s equity interest decreased to approximately 33%. Prior to its contribution to us, Windsor Permian will distribute its remaining interest in Muskie to its member. As a result, we will not own any interest in Muskie when all the outstanding equity interests in Windsor Permian are contributed to us prior to the completion of this offering.

MidMar

We are party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC, or MidMar, an entity that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from us, and we are obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of our Permian Basin acreage. Following the expiration of the initial ten-year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days written notice. Under the gas purchase agreement, MidMar is obligated to pay us a percentage of the net revenue received by MidMar for all components of our dedicated gas. Travis D. Stice, our Chief Executive Officer, has served as a manager on MidMar’s board of managers since April 2011 and as Vice President and Secretary of MidMar since April 2012. An entity controlled by Wexford in which Gulfport and certain entities controlled by Wexford are members owns approximately a 28% equity interest in MidMar. The remaining equity interests in MidMar are owned by nonaffiliated third parties. For the years ended December 31, 2011 and 2010, MidMar paid us $12.2 million and $0.9 million, respectively, and at December 31, 2011 and 2010, MidMar owed us $0.2 million and $0.1 million, respectively, for our portion of the net proceeds from the sale of such gas products and residue gas by MidMar. We were not paid, nor were we owed, any amounts for 2009 by MidMar.

Advisory Services Agreement

Prior to the closing of this offering we will enter into an advisory services agreement with Wexford under which Wexford will provide us with general financial and strategic advisory services related to our business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. This agreement has a term of two years commencing on the completion of this offering. The parties may extend the then current term for additional one-year periods by entering into a written agreement reflecting the terms of such extension at least ten days prior to the expiration of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we are obligated to pay all amounts due through the remaining term of the agreement. In addition, in this agreement we have agreed to pay Wexford to-be-negotiated market-based fees approved by our independent directors for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the advisory services agreement will not extend to our day-to-day business or operations.

Registration Rights

Prior to the closing of this offering, we will enter a registration rights agreements with DB Holdings and Gulfport under which we will grant DB Holdings and Gulfport certain demand and “piggyback” registration rights. For more information regarding this agreement, see “Shares Eligible for Future Sale—Registration Rights” on page 128 of this prospectus.

 

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth certain information with respect to the beneficial ownership of our common stock by:

 

•

each selling stockholder;

 

•

each stockholder known by us to be the beneficial owner of more than five percent of the outstanding shares of our common stock;

 

•

each of our directors;

 

•

each of our named executive officers; and

 

•

all of our directors and executive officers as a group.

Except as otherwise indicated, we believe that each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.

 

Name of Beneficial Owner

Shares Beneficially Owned Prior to Offering

Number of Shares Offered

Shares Beneficially Owned After Offering(1)

Shares to be Sold if Option to Purchase Additional Shares Is Exercised in Full

Shares Beneficially Owned After Offering if Option to Purchase Additional Shares Is Exercised in Full

Number

Percentage

Number

Percentage

Number

Percentage

Selling Stockholders and other 5% Stockholders:

DB Energy Holdings LLC(2)

Gulfport Energy Corporation

Executive Officers and Directors:

Travis D. Stice

Teresa L. Dick

Russell Pantermuehl

Paul Molnar

Michael Hollis

William Franklin

Jeff White

Randall J. Holder

Steven E. West

All executive officers and directors as a group (9 persons)

 

(1)

Percentage of beneficial ownership is based upon shares of common stock outstanding immediately prior to the offering after giving effect to the Contributions, and             shares of common stock outstanding after the offering. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.

(2)

Wexford is the manager of DB Holdings, which is one of the selling stockholders in this offering. The number of shares to be sold in the offering by DB Holdings includes up to              shares that will be sold if the underwriters exercise their option to purchase additional shares in full. As manager of DB Holdings, Wexford has the exclusive authority to,

 

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among other things, purchase, hold and dispose of its assets, including the shares of our common stock that will be owned by DB Holdings. Wexford may, by reason of its status as manager of DB Holdings, be deemed to beneficially own the interest in the shares of our common stock owned by DB Holdings. Each of Charles E. Davidson and Joseph M. Jacobs may, by reason of his status as a controlling person of Wexford, be deemed to beneficially own the interests in the shares of our common stock owned by DB Holdings. Each of Charles E. Davidson, Joseph M. Jacobs and Wexford share the power to vote and to dispose of the interests in the shares of our common stock owned by DB Holdings. Each of Messrs. Davidson and Jacobs disclaims beneficial ownership of the shares of our common stock owned by DB Holdings and Wexford. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.

 

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DESCRIPTION OF CAPITAL STOCK

We will amend and restate our certificate of incorporation and bylaws in connection with this offering. The following description of our common stock, certificate of incorporation and our bylaws are summaries thereof and are qualified by reference to our certificate of incorporation and our bylaws as so amended and restated, copies of which will be filed with the SEC as exhibits to the registration statement of which this prospectus is a part.

Our authorized capital stock consists of              shares of common stock, par value $0.01 per share, and              shares of preferred stock, par value $0.01 per share. We have applied to have our shares of common stock listed on The NASDAQ Global Market under the symbol “FANG.”

Common Stock

Holders of shares of common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Shares of common stock do not have cumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of the board of directors can elect all the directors to be elected at that time, and, in such event, the holders of the remaining shares will be unable to elect any directors to be elected at that time. Our certificate of incorporation denies stockholders any preemptive rights to acquire or subscribe for any stock, obligation, warrant or other securities of ours. Holders of shares of our common stock have no redemption or conversion rights nor are they entitled to the benefits of any sinking fund provisions.

In the event of our liquidation, dissolution or winding up, holders of shares of common stock shall be entitled to receive, pro rata, all the remaining assets of our company available for distribution to our stockholders after payment of our debts and after there shall have been paid to or set aside for the holders of capital stock ranking senior to common stock in respect of rights upon liquidation, dissolution or winding up the full preferential amounts to which they are respectively entitled.

Holders of record of shares of common stock are entitled to receive dividends when and if declared by the board of directors out of any assets legally available for such dividends, subject to both the rights of all outstanding shares of capital stock ranking senior to the common stock in respect of dividends and to any dividend restrictions contained in debt agreements. All outstanding shares of common stock and any shares sold and issued in this offering will be fully paid and nonassessable by us.

Preferred Stock

Our board of directors is authorized to issue up to              shares of preferred stock in one or more series. The board of directors may fix for each series:

 

•

the distinctive serial designation and number of shares of the series;

 

•

the voting powers and the right, if any, to elect a director or directors;

 

•

the terms of office of any directors the holders of preferred shares are entitled to elect;

 

•

the dividend rights, if any;

 

•

the terms of redemption, and the amount of and provisions regarding any sinking fund for the purchase or redemption thereof;

 

•

the liquidation preferences and the amounts payable on dissolution or liquidation;

 

•

the terms and conditions under which shares of the series may or shall be converted into any other series or class of stock or debt of the corporation; and

 

•

any other terms or provisions which the board of directors is legally authorized to fix or alter.

 

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We do not need stockholder approval to issue or fix the terms of the preferred stock. The actual effect of the authorization of the preferred stock upon your rights as holders of common stock is unknown until our board of directors determines the specific rights of owners of any series of preferred stock. Depending upon the rights granted to any series of preferred stock, your voting power, liquidation preference or other rights could be adversely affected. Preferred stock may be issued in acquisitions or for other corporate purposes. Issuance in connection with a stockholder rights plan or other takeover defense could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, control of our company. We have no present plans to issue any shares of preferred stock.

Related Party Transactions and Corporate Opportunities

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

•

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested so long as it has been approved by our board of directors;

 

•

permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

•

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Undesignated preferred stock. The ability to authorize and issue undesignated preferred stock may enable our board of directors to render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings. Our certificate of incorporation and bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the Chief Executive Officer or by a resolution adopted by a majority of our board of directors.

Requirements for advance notification of stockholder nominations and proposals. Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

 

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Stockholder action by written consent. Our bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our stockholders at any annual or special meeting may be effected by written consent of stockholders in lieu of a meeting of stockholders, unless the action to be effected by written consent of stockholders and the taking of such action by such written consent have expressly been approved in advance by our board. This provision, which may not be amended except by the affirmative vote of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for stockholders to initiate or effect an action by written consent that is opposed by our board.

Amendment of the bylaws. Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our certificate of incorporation and bylaws grant our board the power to adopt, amend and repeal our bylaws at any regular or special meeting of the board on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by an affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Removal of Director. Our certificate of incorporation and bylaws provide that members of our board of directors may only be removed by the affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Amendment of the Certificate of Incorporation. Our certificate of incorporation provides that, in addition to any other vote that may be required by law or any preferred stock designation, the affirmative vote of the holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, is required to amend, alter or repeal, or adopt any provision as part of our certificate of incorporation inconsistent with the provisions of our certificate of incorporation dealing with distributions on our common stock, related party transactions, our board of directors, our bylaws, meetings of our stockholders or amendment of our certificate of incorporation.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Transfer Agent and Registrar

             will be the transfer agent and registrar for our common stock.

 

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of substantial amounts of our common stock in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. We cannot predict the effect, if any, that future sales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time.

Sale of Restricted Shares

Upon completion of this offering, we will have              shares of common stock outstanding. Of these shares of common stock, the              shares of common stock being sold in this offering, plus any shares sold upon exercise of the underwriters’ option to purchase additional shares, will be freely tradable without restriction under the Securities Act, except for any such shares held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, which shares will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining              shares of common stock held by our existing stockholder upon completion of this offering, or              shares if the underwriters exercise their option to purchase additional shares in full, will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144 and 701 under the Securities Act, which rules are summarized below. These remaining shares of common stock held by our existing stockholder upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting ” beginning on page 133 of this prospectus, taking into account the provisions of Rules 144 and 701 under the Securities Act.

Rule 144

In general, under Rule 144 as currently in effect, persons who became the beneficial owner of shares of our common stock prior to the completion of this offering may sell their shares upon the earlier of (1) the expiration of a six-month holding period, if we have been subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for at least 90 days prior to the date of the sale and have filed all reports required thereunder, or (2) the expiration of a one-year holding period.

At the expiration of the six-month holding period, assuming we have been subject to the Exchange Act reporting requirements for at least 90 days and have filed all reports required thereunder, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock, and a person who was one of our affiliates at any time during the three months preceding a sale would be entitled to sell, within any three-month period, a number of shares of common stock that does not exceed the greater of either of the following:

 

•

1% of the number of shares of our common stock then outstanding, which will equal approximately              shares immediately after this offering; or

 

•

the average weekly trading volume of our common stock on The NASDAQ Global Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

At the expiration of the one-year holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock without restriction. A person who was one of our affiliates at any time during the three months preceding a sale would remain subject to the volume restrictions described above.

Sales under Rule 144 by our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.

 

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Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchased shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering, or who purchased shares from us after that date upon the exercise of options granted before that date, are eligible to resell such shares in reliance upon Rule 144 beginning 90 days after the date of this prospectus. If such person is not an affiliate, the sale may be made subject only to the manner-of-sale restrictions of Rule 144. If such a person is an affiliate, the sale may be made under Rule 144 without compliance with its one-year minimum holding period, but subject to the other Rule 144 restrictions.

Registration Rights

Prior to the closing of this offering, we will enter into a registration rights agreements with DB Holdings and an investor rights agreement with Gulfport. Under these agreements, each of DB Holdings and Gulfport has demand and “piggyback” registration rights. The demand rights enable each such stockholder to require us to register its shares of our common stock with the SEC at any time, subject to the 180-day lock-up agreement it has entered into in connection with this offering. The piggyback rights will allow each such stockholder to register the shares of our common stock that it owns along with any shares that we register with the SEC. These registration rights are subject to customary conditions and limitations, including the right of the underwriters of an offering to limit the number of shares.

Stock Plans

We intend to file one or more registration statements on Form S-8 under the Securities Act to register shares of our common stock issued or reserved for issuance under our equity incentive plan. The first such registration statement is expected to be filed soon after the date of this prospectus and will automatically become effective upon filing with the SEC. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.

Lock-Up Agreements

We, each of our directors and executive officers, DB Holdings and Gulfport have agreed that, subject to certain exceptions, without the prior written consent of Credit Suisse Securities (USA) LLC, we and they will not, directly or indirectly, for a period of 180 days after the date of the offering (a period that may be extended for up to 18 days under certain circumstances), offer, pledge, sell, contract to sell or otherwise transfer or dispose of any shares of our common stock (other than the shares of our common stock subject to this offering) or any other securities convertible into or exercisable or exchangeable for our common stock. For additional information, see “Underwriting” beginning on page 133 of this prospectus.

 

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a general discussion of material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder (as defined below). This discussion deals only with common stock purchased in this offering that is held as a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, or the Code (generally, property held for investment), by a non-U.S. holder. Except as modified for estate tax purposes, the term “non-U.S. holder” means a beneficial owner of our common stock that is not a “U.S. person” or a partnership for U.S. federal income and estate tax purposes. A U.S. person is any of the following:

 

•

an individual who is a citizen or resident of the United States;

 

•

a corporation (including any entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

 

•

an estate whose income is subject to U.S. federal income taxation regardless of its source; or

 

•

a trust, if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person.

An individual may generally be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of the 183-day calculation, all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

This discussion is based upon provisions of the Code, and Treasury Regulations, administrative rulings and judicial decisions, all as of the date hereof. Those authorities may be changed, perhaps retroactively, so as to result in U.S. federal income and estate tax consequences different from those discussed below. No ruling has been or will be sought from the Internal Revenue Service, or IRS, with respect to the matters discussed below, and there can be no assurance the IRS will not take a contrary position regarding the tax consequences of the acquisition, ownership or disposition of our common stock, or that such contrary position would not be sustained by a court. This discussion does not address all aspects of U.S. federal income and estate taxation and does not deal with other U.S. federal tax laws (such as gift tax laws) or foreign, state, local or other tax considerations that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this discussion does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

 

•

certain former U.S. citizens or residents;

 

•

shareholders that hold our common stock as part of a straddle, constructive sale transaction, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction;

 

•

shareholders that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

 

•

shareholders that are partnerships or entities treated as partnerships for U.S. federal income tax purposes or other pass-through entities or owners thereof;

 

•

shareholders that own, or are deemed to own, more than five percent (5%) of our outstanding common stock (except to the extent specifically set forth below);

 

•

shareholders subject to the alternative minimum tax;

 

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•

financial institutions, banks and thrifts;

 

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insurance companies;

 

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tax-exempt entities;

 

•

real estate investment trusts;

 

•

“controlled foreign corporations,” “passive foreign investment companies” or corporations that accumulate earnings to avoid U.S. federal income tax;

 

•

broker-dealers or dealers in securities or foreign currencies; and

 

•

traders in securities that use a mark-to-market method of accounting for U.S. federal income tax purposes.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the U.S. federal income tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holding our common stock, you should consult your tax advisor.

THIS DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE AND GIFT TAX LAWS TO THEIR PARTICULAR SITUATION AS WELL AS THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS OR TAX TREATIES AND ANY OTHER U.S. FEDERAL TAX LAWS.

Distributions on Common Stock

We do not expect to pay any cash distributions on our common stock in the foreseeable future. However, in the event we do make such cash distributions, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If any such distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock” below. Dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States will be subject to U.S. withholding tax at a 30% rate, or if an income tax treaty applies, a lower rate specified by the treaty. In order to receive a reduced treaty rate, a non-U.S. holder must provide to us or our withholding agent IRS Form W-8BEN (or applicable substitute or successor form) properly certifying eligibility for the reduced rate. Non-U.S. holders that do not timely provide us or our withholding agent with the required certification, but that qualify for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty so requires, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, we or our withholding agent will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements (which may generally be met by providing an IRS Form W-8ECI). In addition, a “branch profits tax” may be imposed at a 30% rate (or a lower rate specified under an applicable income tax treaty) on a foreign corporation’s effectively connected earnings and profits for the taxable year, as adjusted for certain items. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

 

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Gain on Disposition of Common Stock

Subject to the discussion below regarding backup withholding, a non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

 

•

the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States, in which case, the gain will be taxed on a net income basis at the U.S. federal income tax rates and in the manner applicable to U.S. persons, and if the non-U.S. holder is a foreign corporation, the branch profits tax described above may also apply;

 

•

the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements, in which case, the non-U.S. holder will be subject to a flat 30% tax on the gain derived from the disposition (or such lower rate specified by an applicable income tax treaty), which may be offset by U.S. source capital losses, provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses; or

 

•

we are or have been a “United States real property holding corporation”, or USRPHC, for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We have not determined whether we are currently a USRPHC for U.S. federal income tax purposes, but we believe we currently may be a USRPHC. If we are or become a USRPHC, a non-U.S holder nonetheless will not be subject to U.S. federal income tax or withholding in respect of any gain realized on a sale or other disposition of our common stock so long as (i) our common stock is “regularly traded on an established securities market” for U.S. federal income tax purposes and (ii) such non-U.S. holder does not actually or constructively own, at any time during the applicable period described in the third bullet point, above, more than 5% of our outstanding common stock. We expect our common stock to be “regularly traded” on an established securities market, although we cannot guarantee it will be so traded. Accordingly, a non-U.S holder who actually or constructively owns more than 5% of our common stock would be subject to U.S. federal income tax and withholding in respect of any gain realized on any sale or other disposition of common stock (taxed in the same manner as gain that is effectively connected income, except that the branch profits tax would not apply). Non-U.S. holders should consult their own advisor about the consequences that could result if we are, or become, a USRPHC.

Information Reporting and Backup Withholding Tax

Dividends paid to you will generally be subject to information reporting and may be subject to U.S. backup withholding. You will be exempt from backup withholding if you properly provide a Form W-8BEN certifying under penalties of perjury that you are a non-U.S. holder or otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder, or you otherwise establish an exemption. Copies of the information returns reporting such dividends and the tax withheld with respect to such dividends also may be made available to the tax authorities in the country in which you reside.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you receive payments of the proceeds of a disposition of our common stock to or through a U.S. office of a broker, the payment will be subject to both U.S. backup withholding and information reporting unless you properly provide an IRS Form W-8BEN certifying under penalties of perjury that you are a non-U.S. person (and the payor does not have actual knowledge or reason to know that you are a U.S. person) or you otherwise establish an exemption. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S.

 

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information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that has certain relationships with the United States unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption.

Backup withholding is not an additional tax. You may obtain a refund or credit of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability, if any, provided the required information is timely furnished to the IRS.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as defined in the Code) and certain other non-U.S. entities. Specifically, the relevant withholding agent may be required to withhold 30% of any dividends and the proceeds of a sale or other disposition of our common stock paid to (i) a foreign financial institution unless such foreign financial institution undertakes certain diligence and reporting and enters into an agreement with the IRS requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S. owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders or (ii) a non-financial foreign entity that is the beneficial owner of the payment unless such entity certifies that it does not have any substantial United States owners or provides the name, address and taxpayer identification number of each substantial United States owner and such entity meets certain other requirements.

Although these rules currently apply to applicable payments made after December 31, 2012, the IRS has issued Proposed Treasury Regulations providing that withholding will only be made on payments of dividends made on or after January 1, 2014, and on other withholdable payments (including payments of gross proceeds) made on or after January 1, 2015. The Proposed Treasury Regulations described above will not be effective until they are issued in their final form, and as of the date of this prospectus, it is not possible to determine whether the proposed regulations will be finalized in their current form or at all. Prospective investors should consult their tax advisors regarding these withholding provisions.

Federal Estate Tax

Our common stock that is owned (or treated as owned) by an individual who is not a citizen or resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of death will be included in such individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise, and, therefore, may be subject to U.S. federal estate tax.

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated                 , 2012 we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective numbers of shares of common stock:

 

Underwriter		Number of Shares
Credit Suisse Securities (USA) LLC
Total

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

We and the selling stockholders have granted to the underwriters a 30-day option to purchase on a pro rata basis up to an aggregate of              additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $            per share. The underwriters and selling group members may allow a discount of $            per share on sales to other broker/dealers. After the initial public offering the representatives may change the public offering price and concession and discount to broker/dealers. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The following table summarizes the compensation and estimated expenses we and the selling stockholders will pay:

 

		Per Share				Total
		Without Over-allotment		With Over-allotment		Without Over-allotment		With Over-allotment
Underwriting Discounts and Commissions paid by us		$		$		$		$
Expenses payable by us		$		$		$		$
Underwriting Discounts and Commissions paid by selling stockholders		$		$		$		$

We estimate that our out of pocket expenses for this offering will be approximately $            . We have agreed to pay expenses incurred by the selling stockholders in connection with this offering other than the underwriting discounts and commissions.

The representative has informed us that it does not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any

 

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offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension.

Our officers and directors and the selling stockholders have agreed that, subject to certain exceptions, they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension.

Credit Suisse Securities (USA) LLC, in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the common stock and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC will consider, among other factors, the holder’s reasons for requesting the release and the number of shares of common stock or other securities for which the release is being requested.

The underwriters have reserved for sale at the initial public offering price up to                 shares of the common stock for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares.

We and the selling stockholders have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We have applied to list the shares of our common stock on The NASDAQ Global Market under the symbol “FANG”.

In connection with the listing of our common stock on The NASDAQ Global Market, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock will be determined by negotiation between us, the selling stockholders and the underwriters. The principal factors to be considered in determining the initial public offering price include the following:

 

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the general condition of the securities markets;

 

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market conditions for initial public offerings;

 

•

the market for securities of companies in businesses similar to ours;

 

•

the history and prospects for the industry in which we compete;

 

•

our past and present operations and earnings and our current financial position;

 

•

the history and prospects for our business;

 

•

an assessment of our management; and

 

•

other information included in this prospectus and otherwise available to the underwriters.

We cannot assure you that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to this offering or that an active trading market will develop and continue after this offering.

Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and for our affiliates in the ordinary course of business for which they have received and would receive customary compensation.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

 

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

•

Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

 

•

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

 

•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise and, if commenced, may be discontinued at any time.

 

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A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representative may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each such state being referred to herein as a Relevant Member State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (each such date being referred to herein as a Relevant Implementation Date) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) in any other circumstances which do not require the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

United Kingdom

Each underwriter has represented and agreed that:

(a)    it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000, or the FSMA, received by it in connection with the issue or sale of the shares in circumstances in which Section 21(1) of the FSMA does not apply to the Company; and

(b)    it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

 

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Hong Kong

The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan, or the Financial Instruments and Exchange Law, and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

 

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LEGAL MATTERS

The validity of the shares of common stock that are offered hereby by us and the selling stockholders will be passed upon by Akin Gump Strauss Hauer & Feld LLP. The underwriters have been represented by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The audited financial statements included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

Information referenced in this prospectus regarding our estimated quantities of oil and gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Ryder Scott Company L.P. as of December 31, 2011 and by Pinnacle Energy Services, LLC as of December 31, 2010 and 2009, each an independent petroleum engineering firm. Information referenced in this prospectus regarding estimated quantities of oil and gas reserves and the discounted present value of future net cash flows attributable to the Windsor UT properties and the properties subject to the Gulfport contribution is based upon estimates of such reserves and present values prepared in each case by Ryder Scott Company L.P. as of December 31, 2011.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act covering the securities offered by this prospectus, which constitutes a part of that registration statement. Items included in the registration statement as Part II are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus and any prospectus supplement as to the contents of any contract or other document referred to are qualified by reference to each such contract or document filed as part of the registration statement. When we complete this offering, we will be required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

 

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Appendix A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin-centered gas. A regional abnormally-pressured, gas-saturated accumulation in low-permeability reservoirs.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

Bbl/day. Bbl per day.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by non-traditional means.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Deviated well. A well purposely deviated from the vertical using controlled angles to reach an objective location other than directly below the surface location.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Environmental Assessment (EA). A study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

Environmental Impact Statement (EIS). A more detailed study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project that may be made available to the public for review and comment.

 

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Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.

Mcf/day. Mcf per day.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/day. MMcf per day.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/day. MMcfe per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

PDNP. Proved developed non-producing.

 

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PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves (PDP). Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

Tight gas sands. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

 

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Appendix B

WINDSOR PERMIAN LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

		/s/ Don P. Griffin, P.E. Don P. Griffin, P.E. TBPE License No. 64150 Senior Vice President
		RYDER SCOTT COMPANY, L.P. TBPE Firm License No. F-1580		[SEAL]

 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

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January 20, 2012

Windsor Permian LLC

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of Windsor Permian LLC (Windsor) as of December 31, 2011. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 20, 2012 and presented herein, was prepared for public disclosure in Windsor’s filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved, probable and possible liquid hydrocarbon reserves and 100 percent of the total net proved, probable and possible gas reserves of Windsor as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of Windsor

Permian LLC

As of December 31, 2011

 

		Proved
		Developed												Total Proved
		Producing				Non-Producing				Undeveloped
Net Remaining Reserves
Oil/Condensate – MBbl			3,494				311				12,912				16,717
Plant Products – MBbl			1,143				90				3,530				4,763
Gas – MMCF			4,799				388				14,432				19,619
MBOE			5,437				466				18,847				24,750
Income Data ($M)
Future Gross Revenue		$	386,409			$	33,732			$	1,383,530			$	1,803,671
Deductions			115,007				10,909				706,774				832,690
Future Net Income (FNI)		$	271,402			$	22,823			$	676,756			$	970,981
Discounted FNI @ 10%		$	147,447			$	12,090			$	183,910			$	343,447

 

SUITE 600, 1015 4TH STREET, S.W.		CALGARY, ALBERTA T2R 1J4		TEL (403) 262-2799		FAX (403) 262-2790
621 17TH STREET, SUITE 1550		DENVER, COLORADO 80293-1501		TEL (303) 623-9147		FAX (303) 623-4258

 

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		Total Probable Undeveloped				Total Possible Undeveloped
Net Remaining Reserves
Oil/Condensate – MBbl			14,309				4,892
Plant Products – MBbl			3,058				1,024
Gas – MMCF			11,133				3,577
MBOE			19,223				6,512
Income Data ($M)
Future Gross Revenue		$	1,470,059			$	500,339
Deductions			827,874				283,474
Future Net Income (FNI)		$	642,185			$	216,865
Discounted FNI @ 10%		$	134,064			$	42,956

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Windsor. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 96.0 percent and gas reserves account for the remaining 4.0 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account

 

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for approximately 97.2 percent and gas reserves account for the remaining 2.8 percent of total future gross revenue from probable reserves. Liquid hydrocarbon reserves account for approximately 97.3 percent and gas reserves account for the remaining 2.7 percent of total future gross revenue from possible reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income As of December 31, 2011 ($M)
Discount Rate Percent		Total Proved		Total Probable		Total Possible
5		$539,390		$283,594		$93,201
15		$236,843		$  59,858		$18,649
20		$171,787		$  18,984		$  5,580
25		$128,974		$  -4,953		$ -1,903

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Windsor’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

 

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Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Windsor’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved, probable and possible reserves actually recovered and amounts of proved, probable and possible income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Windsor owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These

 

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analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods, analogy, or a combination of both methods. Approximately 85 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Windsor and were considered sufficient for the purpose thereof. The remaining 15 percent of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All proved, probable, and possible developed non-producing and undeveloped reserves included herein were estimated by the analogy method.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.

 

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Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Windsor has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by Windsor with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Windsor. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Windsor. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 

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Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weighted arithmetic average as previously described.

As noted above, Windsor furnished us with the average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Windsor and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Windsor to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area

Product

Price Reference

Avg Benchmark Prices

Avg Proved Realized Prices

Avg Probable Realized Prices

Avg Possible Realized Prices

North America

United States

Oil/Condensate

WTI Cushing

$

96.19/Bbl

$

93.09/Bbl

$

92.89/Bbl

$

92.85/Bbl

NGLs

WTI Cushing

$

61.97/Bbl

$

56.33/Bbl

$

57.02/Bbl

$

56.91/Bbl

Gas

Henry Hub/ Colorado Interstate

$

4.12/MMBTU

$

3.91/MCF

$

3.95/MCF

$

3.95/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

 

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Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Windsor and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Windsor. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Windsor and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Windsor’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Windsor’s estimate.

The proved, probable and possible developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Windsor’s plans to develop these reserves as of December 31, 2011. The implementation of Windsor’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Windsor’s management. As the result of our inquiries during the course of preparing this report, Windsor has informed us that the development activities included herein have been subjected to and received the internal approvals required by Windsor’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Windsor. Additionally, Windsor has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Windsor were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or

 

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a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Windsor. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Windsor.

We have provided Windsor with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Windsor and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

 

DPG/pl		[SEAL]

 

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2011 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

 

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Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

 

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POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves.    Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: SOCIETY OF

PETROLEUM ENGINEERS (SPE) WORLD

PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

 

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

 

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(2)

wells which were shut-in for market conditions or pipeline connections; or

 

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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Appendix C

WINDSOR UT, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

 

 

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm License No. F-1580

 

 

 

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January 20, 2012

Windsor UT, LLC

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved and probable reserves, future production, and income attributable to certain leasehold interests of Windsor UT (Windsor) as of December 31, 2011. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 20, 2012 and presented herein, was prepared for public disclosure in Windsor’s filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved and probable liquid hydrocarbon reserves and 100 percent of the total net proved and probable gas reserves of Windsor as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Windsor UT, LLC

As of December 31, 2011

 

 

		Proved
		Developed								Undeveloped				Total     Proved
		Producing				Non-Producing
Net Remaining Reserves
Oil/Condensate – MBbl			109				34				1,240				1,383
Plant Products – MBbl			23				7				256				286
Gas – MMCF			76				23				834				933
MBOE			145				45				1,635				1,825
Income Data ($M)
Future Gross Revenue		$	11,199			$	3,512			$	126,439			$	141,150
Deductions			3,327				1,561				70,584				75,472
Future Net Income (FNI)		$	7,872			$	1,951			$	55,855			$	65,678
Discounted FNI @ 10%		$	4,449			$	829			$	12,730			$	18,008

 

SUITE 600, 1015 4TH STREET, S.W. 621 17TH STREET, SUITE 1550		CALGARY, ALBERTA T2R 1J4 DENVER, COLORADO 80293-1501		TEL (403) 262-2799 TEL (303) 623-9147		FAX (403) 262-2790 FAX (303) 623-4258

 

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		Total Probable     Undeveloped
Net Remaining Reserves
Oil/Condensate – MBbl			2,583
Plant Products – MBbl			533
Gas – MMCF			1,737
MBOE			3,406
Income Data ($M)
Future Gross Revenue		$	263,414
Deductions			147,050
Future Net Income (FNI)		$	116,364
Discounted FNI @ 10%		$	18,984

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Windsor. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development

 

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costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 97.5 percent and gas reserves account for the remaining 2.5 percent of total future gross revenue from proved reserves. Liquid hydrocarbon reserves account for approximately 97.5 percent and gas reserves account for the remaining 2.5 percent of total future gross revenue from probable reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income         As of  December 31, 2011 ($M)
Discount Rate             Percent		Total Proved				Total Probable
5		$	32,528			$	45,247
15		$	10,383			$	7,624
20		$	5,895			$	2,283
25		$	3,054			$	-309

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities

 

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determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Windsor’s request, this report addresses the proved and probable reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved and probable based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Windsor’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ significantly from the estimated quantities.

 

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The estimates of reserves presented herein were based upon a detailed study of the properties in which Windsor owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

 

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The proved and probable reserves for the properties included herein were estimated by performance methods, analogy, or a combination of both methods. Approximately 85 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Windsor and were considered sufficient for the purpose thereof. The remaining 15 percent of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All proved and probable developed non-producing and undeveloped reserves included herein were estimated by the analogy method.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Windsor has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by Windsor with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Windsor. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities

 

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and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Windsor. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weighted arithmetic average as previously described.

As noted above, Windsor furnished us with the average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

 

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The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Windsor and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Windsor to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area		Product		Price Reference		Avg Benchmark Prices		Avg Proved Realized Prices		Avg Probable Realized Prices
North America
United     States		Oil/Condensate		WTI Cushing		$96.19/Bbl		$92.99/Bbl		$92.99/Bbl
		NGLs		WTI Cushing		$61.97/Bbl		$56.74/Bbl		$56.74/Bbl
				Henry Hub/ Colorado Interstate
		Gas				$4.12/MMBTU		$3.92/MCF		$3.92/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Windsor and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Windsor. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Windsor and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Windsor’s estimates of zero abandonment costs

 

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after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Windsor’s estimate.

The proved and probable developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Windsor’s plans to develop these reserves as of December 31, 2011. The implementation of Windsor’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Windsor’s management. As the result of our inquiries during the course of preparing this report, Windsor has informed us that the development activities included herein have been subjected to and received the internal approvals required by Windsor’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Windsor. Additionally, Windsor has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Windsor were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Windsor. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

 

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The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Windsor.

We have provided Windsor with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Windsor and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

 

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

DPG/pl

 

 

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2011 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature

 

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of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

 

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves.    Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

 

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Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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Appendix D

GULFPORT ENERGY CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

		\s\ Don P. Griffin
		Don P. Griffin, P.E.
		TBPE License No. 64150
		Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

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January 13, 2012

Gulfport Energy Corporation

14313 N. May, Suite 100

Oklahoma City, Oklahoma 73134

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Gulfport Energy Corporation (Gulfport) as of December 31, 2011. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 6, 2012, and presented herein, was prepared for public disclosure by Gulfport in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Gulfport as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Gulfport Energy Corporation

As of December 31, 2011

 

		Proved
		Developed												Total Proved
		Producing				Non-Producing				Undeveloped
Net Remaining Reserves
Oil/Condensate – Mbbl			1,853				244				5,989				8,086
Plant Products – Mbbl			660				46				2,085				2,791
Gas – MMCF			2,853				197				8,996				12,046
Income Data ($M)
Future Gross Revenue		$	210,025			$	24,859			$	675,799			$	910,683
Deductions			52,844				2,238				348,154				403,236
Future Net Income (FNI)		$	157,181			$	22,621			$	327,645			$	507,447
Discounted FNI @ 10%		$	84,900			$	14,551			$	102,837			$	202,288

 

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4		TEL (403) 262-2799		FAX (403) 262-2790
621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501		TEL (303) 623-9147		FAX (303) 623-4258

 

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The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Gulfport. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 94.9 percent and gas reserves account for the remaining 5.1 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income ($M) As of December 31, 2011
Discount Rate Percent		Total Proved
5		$303,812
15		$144,573
20		$108,577
25		$  84,579

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

 

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The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Gulfport’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Gulfport’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Gulfport owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the

 

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Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods involved decline curve analysis which utilized extrapolations of historical production and pressure data available through October 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Gulfport or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated by analogy or a combination of performance and analogy. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic

 

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producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Gulfport has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Gulfport with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Gulfport. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Gulfport. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the

 

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contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Gulfport furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Gulfport. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Gulfport to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area

Product

Price Reference

Average Benchmark Prices

Average Realized Prices

North America

United States

Oil/Condensate

WTI Cushing

$

96.19/Bbl

$

93.11/Bbl

NGLs

WTI Cushing

$

96.19/Bbl

$

57.09/Bbl

Gas

Henry Hub — Colorado Interstate

$

4.12/MMBTU

$

4.04/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Gulfport and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Gulfport. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Gulfport and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Gulfport’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Gulfport’s estimate.

 

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The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Gulfport’s plans to develop these reserves as of December 31, 2011. The implementation of Gulfport’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Gulfport’s management. As the result of our inquiries during the course of preparing this report, Gulfport has informed us that the development activities included herein have been subjected to and received the internal approvals required by Gulfport’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Gulfport. Additionally, Gulfport has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Gulfport were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Gulfport. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Gulfport.

We have provided Gulfport with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Gulfport and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

[SEAL]

DPG/pl

 

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. As part of his 2009 continuing education hours, Mr. Griffin attended an internally presented 16 hours of formalized training relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Griffin attended an additional 15 hours of training during 2010 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

 

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Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

 

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Shut-In

Shut-in Reserves are expected to be recovered from:

 

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

 

(2)

wells which were shut-in for market conditions or pipeline connections; or

 

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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INDEX TO FINANCIAL STATEMENTS

 

Windsor Permian LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2011 and 2010			F-3
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009			F-4
Consolidated Statement of Changes in Member’s Equity for the Years Ended December  31, 2009, 2010 and 2011			F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009			F-6
Notes to Consolidated Financial Statements			F-7
Windsor UT LLC
Report of Independent Certified Public Accountants			F-28
Balance Sheets as of December 31, 2011 and 2010			F-29
Statements of Operations for the Year Ended December 31, 2011 and Period from Inception (April  28, 2010) to December 31, 2010			F-30
Statement of Changes in Member’s Equity for the Period From Inception (April 28, 2010) to December 31, 2010 and the Year Ended December 31, 2011			F-31
Statements of Cash Flows for the Year Ended December 31, 2011 and Period from Inception (April 28, 2010) to December 31, 2010			F-32
Notes to Financial Statements			F-33
Statements of Revenues and Direct Operating Expenses of Certain Property Interests of Gulfport Energy Corporation
Report of Independent Certified Public Accountants			F-42
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2011 and 2010			F-43
Notes to Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2011 and 2010			F-44

 

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Report of Independent Registered Public Accounting Firm

Members

Windsor Permian LLC

We have audited the accompanying consolidated balance sheets of Windsor Permian LLC and subsidiaries (collectively the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in member’s equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Windsor Permian LLC and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted the new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

March 23, 2012

 

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Windsor Permian LLC and Subsidiaries

Consolidated Balance Sheets

 

		December 31,
		2011				2010
Assets
Current assets:
Cash and cash equivalents		$	6,802,389			$	4,089,745
Accounts receivable:
Joint interest and other			3,734,513				3,540,244
Oil and natural gas sales			838,791				305,500
Related party			13,122,589				8,342,033
Inventories			6,006,355				8,433,734
Prepaid expenses and other			428,202				326,148
Total current assets			30,932,839				25,037,404
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($1,732,329 and $825,742 excluded from amortization at December 31, 2011 and December 31, 2010, respectively)			325,510,080				239,771,620
Other property and equipment			1,016,574				11,915,780
Accumulated depletion, depreciation, amortization and impairment			(119,500,035	)			(104,845,670	)
			207,026,619				146,841,730
Investments-equity method			10,309,668				—
Other assets			1,214,759				637,562
Total assets		$	249,483,885			$	172,516,696
Liabilities and Member’s Equity
Current liabilities:
Accounts payable trade		$	8,769,491			$	8,641,089
Accounts payable–related party			3,436,195				4,785,810
Accrued capital expenditures			13,922,932				5,387,746
Other accrued liabilities			4,804,069				696,583
Revenues and royalties payable			3,165,267				499,048
Derivative contracts			8,320,351				—
Total current liabilities			42,418,305				20,010,276
Note payable credit facility–long term			85,000,000				44,766,687
Derivative contracts			6,138,573				1,373,864
Asset retirement obligations			1,079,725				727,826
Total liabilities			134,636,603				66,878,653
Commitments and contingencies (Note 11)
Member’s equity			114,847,282				105,638,043
Total liabilities and member’s equity		$	249,483,885			$	172,516,696

See accompanying notes to consolidated financial statements.

 

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Operations

 

		Year Ended December 31,
		2011				2010				2009
Revenues:
Oil sales-related party		$	38,178,686			$	21,402,799			$	8,815,681
Oil sales			2,582,019				74,574				973,058
Natural gas sales			1,646,848				1,400,584				922,137
Natural gas liquid sales			4,773,249				3,563,970				2,005,135
Oil and natural gas services-related party			1,490,910				811,247				—
Total revenues			48,671,712				27,253,174				12,716,011
Costs and expenses:
Lease operating expenses			8,218,217				3,039,462				1,551,047
Lease operating expenses-related party			2,127,138				1,549,097				815,576
Production taxes-related party			1,759,601				993,383				406,627
Production taxes			574,252				353,496				256,441
Gathering and transportation			201,828				105,870				42,091
Oil and natural gas services			1,207,101				228,046				—
Oil and natural gas services –related party			525,791				583,201				—
Depreciation, depletion and amortization			15,402,826				8,145,143				3,215,891
General and administrative expenses-related party			3,160,512				2,656,278				4,632,671
General and administrative expenses			442,967				395,349				429,947
Asset retirement obligation accretion expense			63,259				37,856				27,934
Total costs and expenses			33,683,492				18,087,181				11,378,225
Income from operations			14,988,220				9,165,993				1,337,786
Other income (expense)
Interest income			11,197				34,474				35,075
Interest expense			(2,528,058	)			(836,265	)			(10,938	)
Loss on derivative contracts			(13,009,393	)			(147,983	)			(4,068,005	)
Loss from equity investment			(7,017	)			—				—
Total other expense, net			(15,533,271	)			(949,774	)			(4,043,868	)
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma information-(unaudited)
Net income (loss) before income taxes, as reported		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma provision (benefit) for income tax			—				—				—
Pro forma net (loss) income		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma income (loss) per common share — basic and diluted		$
Weighted average pro forma shares outstanding — basic and diluted

See accompanying notes to consolidated financial statements.

 

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Windsor Permian LLC and Subsidiaries

Consolidated Statement of Changes in Member’s Equity

 

		Total member’s equity
Balance at January 1, 2009		$	70,615,293
Contributions			16,893,000
Distributions			(600,000	)
Net loss			(2,706,082	)
Balance at December 31, 2009			84,202,211
Contributions			18,798,613
Distributions			(5,579,000	)
Net income			8,216,219
Balance at December 31, 2010			105,638,043
Contributions			9,210,000
Equity based compensation			544,290
Net loss			(545,051	)
Balance at December 31, 2011		$	114,847,282

See accompanying notes to consolidated financial statements.

 

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Cash Flows

 

		Year Ended December 31,
		2011				2010				2009
Cash flows from operating activities:
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Asset retirement obligation accretion expense			63,259				37,856				27,934
Depreciation, depletion, and amortization			15,905,315				8,145,143				3,215,891
Amortization of debt issuance costs			250,010				163,297				10,937
Loss on derivative contracts			13,009,393				147,983				4,068,005
(Gain) loss on sale of assets			(22,942	)			(4,675	)			1,588
Equity-based compensation expense			544,290				—				—
Changes in operating assets and liabilities:
Accounts receivable			(1,085,025	)			(1,822,949	)			592,489
Accounts receivable-related party			(4,780,556	)			(6,793,208	)			(1,548,825	)
Inventories			(871,969	)			(4,896,909	)			83,048
Prepaid expenses and other			(201,732	)			(326,148	)			—
Accounts payable and accrued liabilities			2,656,836				1,952,645				(597,506	)
Accounts payable and accrued liabilities-related party			759,377				(408,892	)			(445,913	)
Revenues and royalties payable			2,666,219				499,048				—
Revenues and royalties payable-related party			2,036,770				266,414				—
Net cash provided by operating activities			30,384,194				5,175,824				2,701,566
Cash flows from investing activities:
Additions to oil and natural gas properties			(58,159,977	)			(7,623,975	)			(26,622,735	)
Additions to oil and natural gas properties-related party			(17,219,632	)			(34,849,118	)			—
Proceeds from sale of oil and natural gas properties			—				1,250,000				—
Purchase of other property and equipment			(7,064,972	)			(11,741,073	)			(8,856	)
Proceeds from sale of property and equipment			54,909				20,075				2,000
Settlement of non-hedge derivative instruments			(4,126,800	)			(3,962,440	)			(2,770,026	)
Receipt (payment) on derivative margins			4,202,467				3,771,890				(2,750,000	)
Deconsolidation of Bison			(9,536	)			—				—
Proceeds from sale of membership interest in equity investment			6,009,499				—				—
Net cash used in investing activities			(76,314,042	)			(53,134,641	)			(32,149,617	)
Cash flows from financing activities:
Borrowing on credit facility			40,233,313				61,066,687				7,650,000
Repayment on credit facility			—				(23,950,000	)			—
Debt issuance costs			(770,462	)			(718,046	)			(50,000	)
Initial public offering costs			(30,359	)			—				(43,750	)
Contributions by members			9,210,000				18,798,613				16,893,000
Distributions by members			—				(5,579,000	)			(600,000	)
Net cash provided by financing activities			48,642,492				49,618,254				23,849,250
Net increase (decrease) in cash and cash equivalents			2,712,644				1,659,437				(5,598,801	)
Cash and cash equivalents at beginning of period			4,089,745				2,430,308				8,029,109
Cash and cash equivalents at end of period		$	6,802,389			$	4,089,745			$	2,430,308
Supplemental cash flow information
Interest paid, net of capitalized interest		$	2,265,005			$	600,194			$	—
Asset retirement obligation incurred, including changes in estimate		$	288,640			$	208,083			$	79,666

See accompanying notes to consolidated financial statements.

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements

1. Organization

Windsor Permian LLC (“Windsor”) is a limited liability company formed on October 23, 2007 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of Windsor are not liable for the liabilities or other obligations of Windsor. Windsor is wholly owned by an investment fund which is controlled and managed by Wexford Capital LP (“Wexford”). Collectively, Windsor and its subsidiaries, Bison Drilling and Field Services LLC (formerly known as Windsor Drilling LLC) through March 31, 2011, and West Texas Field Services LLC, are referred to in these financial statements as the “Company”.

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others.

2. Summary of Significant Accounting Policies

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of Windsor and its wholly owned subsidiaries, except for the accounts of Bison Drilling and Field Services LLC, which has been excluded from the Company’s consolidated financial statements effective March 31, 2011 (Note 5). All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company utilizes bank deposit accounts which periodically sweep available cash into uninsured short-term investment securities. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. As discussed in Note 10, through February 26, 2010 a significant portion of the Company’s oil and natural gas properties were contractually operated by an affiliate. Prior to February 26, 2010, purchasers remitted payment for production to the affiliated operator and the affiliated operator, in turn, remitted payment to the Company. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2011, 2010 and 2009.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives and note payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Derivatives are recorded at fair value (see Note 9).

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized general and administrative costs were $871,036 for the year ended December 31, 2011, and no amounts were capitalized for the years ended December 31, 2010 and 2009. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 5). Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $25.40, $17.78 and $11.21 for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $15,178,366, $7,373,126 and $3,155,084 for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense.

Beginning December 31, 2009, the Company used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2011, 2010 or 2009.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

Other Property and Equipment

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense was $726,949, $772,017 and $60,807 for the years ended December 31, 2011, 2010 and 2009, respectively.

Impairment of Long-Lived Assets

Other long-lived assets, drilling rigs and related equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2011, 2010 or 2009.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2010 and 2009, the Company capitalized interest expense totaling $150,280 and $54,322, respectively. During the year ended December 31, 2011, the Company did not capitalize any interest expense.

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Inventories

Inventories are stated at the lower of cost or market and consist of the following:

 

		December 31,
		2011				2010
Tubular goods and equipment		$	5,630,208			$	8,269,628
Crude oil			376,147				164,106
		$	6,006,355			$	8,433,734

The Company’s tubular goods and equipment is primarily comprised of oil and gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2011, the Company estimated that all of its tubular goods and equipment will be utilized within one year. The total inventory includes tubular goods in transit of $1,093,708 and $1,377,567 at December 31, 2011 and 2010, respectively. Some of the tubular and casing pipe has been purchased, at cost, from an affiliated company. The Company owed this affiliate $68,875 at December 31, 2010, and did not have an outstanding balance with the affiliated company at December 31, 2011. This amount is included in accounts payable-related party in the consolidated balance sheets.

Debt issuance costs

The Company amortizes debt issuance costs related to its credit facility as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were $1,167,621 and $637,562 as of December 31, 2011 and 2010, respectively. The Company includes the unamortized costs in other assets in its consolidated balance sheets.

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2011 and 2010. Revenues from oil and natural gas services are recognized as services are provided.

Investments

Equity investments in which the Company exercises significant influence but does not control, are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

is recognized in the statement of operations. However, because substantially all of Bison’s earnings are generated by performing services on properties owned and operated by the Company, the Company’s share of Bison’s earnings has not been recognized but has been credited to oil and gas properties. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments at December 31, 2011. For additional information on the Company’s investments, see Note 5.

Accounting for Equity-Based Compensation

The Company accounts for equity-based compensation in accordance with the provisions of FASB ASC Topic 718, “Compensation—Stock Compensation” (“FASB ASC 718”). FASB ASC 718 requires equity-based payments to employees to be recognized as expense over the applicable service period based on the fair value of the award on the date of grant.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the years ended December 31, 2011 and 2010, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for 78% and 81% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Commodity Risk Management

The Company has used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. Changes in the fair value of instruments designated as a fair value hedge offset changes in the fair value of the hedged item and changes in the fair value of instruments designated as cash flow hedges are shown in accumulated other comprehensive income until the hedged item is recognized in earnings. For derivative instruments not designated as hedging instruments, the unrealized gain or loss on the change in fair value of these instruments are recognized in earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments during the years ended December 31, 2011, 2010 and 2009.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as limited liability companies, are not subject to federal income taxes. As appropriate, the taxable income or loss applicable to those operations is included in the federal income tax returns

 

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Notes to Consolidated Financial Statements-(Continued)

 

of the respective owners and no income tax effect is included in the accompanying consolidated financial statements. The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2011, 2010 and 2009, there was no margin tax expense. The Company’s 2008, 2009 and 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2011 and 2010, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2011, 2010 and 2009, there was no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements.

Unaudited Pro Forma Income Taxes and Earnings Per Share

Prior to the completion of a proposed 2012 initial public offering of common stock (“IPO”) by Diamondback Energy, Inc. (“Diamondback”), all the equity interests in Windsor will be contributed to Diamondback and Windsor will become a wholly-owned subsidiary of Diamondback (“Proposed Contribution Transaction”). Diamondback, a holding company formed on December 30, 2011 which will not conduct any material business operations prior to the Proposed Contribution Transaction, is a C-Corp under the Internal Revenue Code and is subject to income taxes. Accordingly, the Company computed a pro forma income tax provision as if the Company were a C-Corp for all periods presented. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. However, on a pro forma basis, management has determined that any net deferred income tax asset would not be realizable; therefore, tax expense would be zero for all periods. Additionally, upon Windsor becoming a subsidiary of Diamondback, the Company will establish a net deferred tax liability for differences between the tax and book basis of the Company’s assets and liabilities, and record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at December 31, 2011 the amount of this charge would have been approximately $26.2 million.

Also, upon completion of the Proposed Contribution Transaction, the Company will present pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share will be computed by dividing net income attributable to the Company by the number of shares of common stock outstanding as if the shares of Diamondback issued in the Proposed Contribution Transaction were issued and outstanding for the year ended December 31, 2011.

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a

 

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Notes to Consolidated Financial Statements-(Continued)

 

more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		December 31,
		2011				2010
Oil and natural gas properties:
Subject to depletion		$	323,777,751			$	238,945,878
Not subject to depletion-acquisition costs
Incurred in 2011			1,199,679				—
Incurred in 2010			—				293,092
Incurred in 2009			532,650				532,650
Total not subject to depletion			1,732,329				825,742
Gross oil and natural gas properties			325,510,080				239,771,620
Less accumulated depreciation, depletion, amortization and impairment			(119,167,476	)			(103,989,110	)
Oil and natural gas properties, net			206,342,604				135,782,510
Drilling rigs			—				7,622,586
Workover rigs and related equipment			—				3,304,577
Other property and equipment			1,016,574				988,617
Less accumulated depreciation			(332,559	)			(856,560	)
Other property and equipment, net			684,015				11,059,220
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	207,026,619			$	146,841,730

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

 

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ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

A reconciliation of the asset retirement obligation is as follows:

 

		Year Ended December 31,
		2011				2010				2009
Asset retirement obligation, beginning of period		$	727,826			$	481,887			$	374,287
Additional liability incurred			288,640				208,083				79,666
Accretion expense			63,259				37,856				27,934
Asset retirement obligation, end of period			1,079,725				727,826				481,887
Less current portion			—				—				—
Asset retirement obligations - long-term		$	1,079,725			$	727,826			$	481,887

5. Equity Method Investments

Bison Drilling and Field Services LLC

The Company held a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC, formed on November 15, 2010. In addition, the Company also held a wholly owned subsidiary, West Texas Field Services LLC, formed on March 2, 2010 which, on January 1, 2011, contributed all of its assets and liabilities to Bison. Bison owns and operates four drilling rigs and various oil and gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it maintained significant influence but it no longer had the ability to exercise control over Bison. The Company deconsolidated Bison for financial reporting purposes as of March 31, 2011 and the previously consolidated amounts were removed from the consolidated balance sheet and reflected as an equity method investment. The Company now reflects its investment in Bison on the equity method basis of accounting. The Company eliminates any intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest.

An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.

The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market

 

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Notes to Consolidated Financial Statements-(Continued)

 

price from a third party in December 2010 and the second two were purchased from the same third party in April 2011. The Company also reviewed pricing of similar rigs in the market through retail and auction transactions. Because the rigs had just recently been purchased and this purchase price was in line with other outside transactions, the Company determined that Bison’s book value equaled fair value. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

In September 2011, the Company completed the sale of 25% of its membership interest in Bison to a related party. The Company internally reviewed the fair value of Bison and, because the effective date of this transaction was May 1, 2011 and was within thirty days of the above valuation, the Company concluded the value of Bison had not changed. The Company determined that fair value equaled book value at the date of this transaction. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

The Company has a 27.2% ownership in Bison at December 31, 2011. As of December 31, 2011, the Company’s investment in Bison is reflected as a non-current asset of $6,172,480.

The table below summarizes financial information for Bison as of December 31, 2011:

 

		December 31, 2011
Current assets		$	4,438,458
Property and equipment, net			21,707,528
Other assets			880,213
Current liabilities			2,418,902
Equity			24,607,297

Muskie Holdings LLC

During 2011, the Company paid approximately $4,200,000 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC, a Delaware limited liability company, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, it is expected that the Company’s interest in Muskie will decrease through 2012 to approximately 13%. Muskie generated a loss in 2011 and the Company has recorded its share of this loss. As of December 31, 2011, the Company’s investment in Muskie is reflected as a non-current asset of $4,137,188.

The table below summarizes financial information for Muskie as of December 31, 2011:

 

		December 31, 2011
Current assets		$	994,166
Property and equipment, net			7,584,779
Current liabilities			26,816
Equity			8,552,129

 

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6. Revolving Bank Credit Facility

Credit Facility-BNP Paribus

On October 15, 2010, the Company executed a secured loan agreement with BNP Paribas (“BNP”) as the administrative agent, sole book runner and lead arranger. The loan agreement originally provided for a maximum principal amount of $100 million and was increased to $250 million through an amendment dated December 30, 2011. The loan agreement is subject to a collateral borrowing base calculation which is based on the Company’s oil and natural gas reserves (the “borrowing base”). The loan bears interest at a rate elected by the Company that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.00% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal is payable voluntarily by the Company or is required to be paid (i) if the loan amount exceeds the borrowing base; (ii) if the lender elects to require periodic payments as a part of a borrowing base re-determination; and (iii) at the maturity date of October 14, 2014. The Company is obligated to pay, quarterly, a commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of the Company’s assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st (a “scheduled redetermination”). In addition, the Company may request an additional three redeterminations of the borrowing base between scheduled redeterminations. The borrowing base was $45 million at December 31, 2010. The borrowing base increased throughout 2011 through various redeterminations and at December 31, 2011 the borrowing base was $100 million. The current lenders and their percentage commitments in the reserve-based credit facility are BNP (45%), Amegy Bank of Texas (25%), US Bancorp (25%) and West Texas National Bank (5%).

As of December 31, 2011 and 2010, the Company had outstanding borrowings of $85,000,000 and $44,766,687, respectively. The credit facility bears a weighted average interest rate of 3.3% and 3.5% as of December 31, 2011 and 2010, respectively.

The agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.

 

Financial Covenant		Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement		Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX		Not greater than 3.5 to 1.0
Current ratio, as defined in the credit agreement		Not less than 1.0 to 1.0

As of December 31, 2011 and 2010, the Company was in compliance with all financial covenants under the revolving bank credit facility. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

Credit Facility-Bank of Oklahoma, N.A.

On September 17, 2009, the Company entered into a revolving credit facility with the Bank of Oklahoma, N.A. (“BOK”). This revolving credit facility was repaid and closed in October 2010 with borrowings from the BNP revolving credit facility. The BOK revolving credit facility had a maximum principal amount of $50 million; subject to a collateral borrowing base calculation, which was based on the underlying reserve value of the oil and natural gas properties securing the credit facility and outstanding letters of credit.

 

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7. Derivatives

The Company has used price swap derivatives to reduce price volatility associated with certain of its oil sales. In these swaps, the Company receives the fixed price per the contract and pays a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to the Company’s derivative contracts are BNP Paribas (“BNP”) and Hess Corporation (“Hess”), who the Company believes are acceptable credit risks.

All derivative financial instruments are recorded on the consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

On October 4, 2011, in order to lock-in prices on the anticipated base level of production, while at the same time providing downside protection for the Borrowing Base, the Company executed with BNP, West Texas Intermediate light sweet crude oil swaps on the NYMEX for calendar year 2012 and 2013 of one thousand barrels per day priced at $78.50 and $80.55, respectively.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2011.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				December 31, 2011
										Fair Value Liability
Crude Oil Swaps:
January – November 2012			335,000			$	78.50			$	6,833,265
December 2012			31,000			$	78.50				594,223
January – December 2013			365,000			$	80.55				5,544,350

The Company enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, the Company receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, the Company placed a swap contract with Hess covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, the Company entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, the Company entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps.

 

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Notes to Consolidated Financial Statements-(Continued)

 

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2011 and 2010, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
December 2010			22,000			$	82.80			$	99.45–103.20			$	—			$	392,462
January – November 2011			180,000				82.90				98.50–102.20				—				4,159,695
December 2011			90,000				82.90				98.50–102.20				378,750				377,314
January – December 2012			270,000				85.07				98.25–101.80				3,876,959				3,844,101

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2011 and 2010, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Asset				Fair Value Asset
Crude Oil Swaps:
December 2010			8,000				82.80				75.00			$	—			$	62,400
January – November 2011			82,500				82.90				78.42				—				369,205
December 2011			7,500				82.90				78.42				33,600				33,503
January – December 2012			90,000				85.07				80.52				409,380				406,489

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations:

 

		Years Ended December 31,
		2011				2010				2009
Unrealized loss on open non-hedge derivative instruments		$	12,971,838			$	—			$	—
Unrealized loss on locked-in non-hedge derivative instruments			—				—				1,297,979
Loss on settlement of non-hedge derivative instruments			37,555				147,983				2,770,026
Loss on derivative contracts		$	13,009,393			$	147,983			$	4,068,005

The Company is required to provide margin deposits to Hess whenever its unrealized losses exceed predetermined credit limits. The Company had a margin deposit held by Hess of $2,325,643 and $6,528,111 as of December 31, 2011 and 2010, respectively, which earns interest that is remitted to the Company. As the Company has a master netting agreement with Hess, the Company has offset this margin deposit against its derivative positions.

 

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8. Equity-Based Compensation

During the year ended December 31, 2011, the Company granted to its executive officers options to acquire membership interests in the Company. Such options vest in four equal annual installments commencing on the first anniversary of the date of grant and are exercisable for five years from the date of grant. Generally, in the event more than 50% of the combined voting power of the Company is not owned by Wexford or its affiliates and there is a material change in the terms of the option holder’s employment, the options will vest immediately. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

 

Grants Made During the Months Ended		Membership Interest Granted				Exercise Price				Fair Value at Date of Grant
April 2011			1.00	%		$	3,600,000			$	1,452,851
August 2011			1.20	%			6,000,000				1,383,976
September 2011			1.25	%			5,900,000				1,532,612
November 2011			0.25	%			1,250,000				288,328
			3.70	%		$	16,750,000			$	4,657,767

At December 31, 2011, for outstanding options, the intrinsic value was $112,500 and the weighted-average remaining contractual terms were 4.6 years. Also, at December 31, 2011, no options were exercisable.

The Company accounts for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost is recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price, and the Company’s expectations regarding dividends.

The Company does not have a history of market prices for its membership interests because such interests are not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:

 

		Year Ended December 31, 2011
Expected term			5 years
Risk-free interest rate			0.96	%
Expected volatility			45.50	%
Expected dividend yield			0.00	%

As of December 31, 2011, the Company assumed no annual forfeiture rate because of its lack of turnover and lack of history for this type of award. The Company will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover behavior, and other factors.

 

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Notes to Consolidated Financial Statements-(Continued)

 

Changes in the estimated forfeiture rate can have a significant effect on reported equity-based compensation expense, because the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed.

Equity-based compensation expense recorded for the year ended December 31, 2011 was $544,290. The unrecognized equity-based compensation expense as of December 31, 2011 was $4,113,477 related to these awards which is expected to be recognized over a weighted-average period of 3.6 years. No equity-based compensation expense was recorded for the years ended December 31, 2010 and 2009 as the Company had not historically issued equity-based compensation awards.

9. Fair Value Measurements

The Company measures and discloses fair value in accordance with ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”). Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

ASC Topic 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

The three levels of the fair value hierarchy defined by ASC Topic 820 are as follows:

Level 1—Pricing inputs include quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs include quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

 

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Notes to Consolidated Financial Statements-(Continued)

 

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010.

 

		Quoted Prices in Active Markets Level 1				Significant Other Observable Inputs Level 2				Significant Unobservable Inputs Level 3				Cash Collateral(1)				Net Fair Value
Financial Liabilities
		December 31, 2011
Derivative contracts		$	—			$	16,784,567			$	—			$	(2,325,643	)		$	14,458,924
		December 31, 2010
Derivative contracts		$	—			$	7,901,975			$	—			$	(6,528,111	)		$	1,373,864

 

(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Level 2 Fair Value Measurements

Derivative contracts-The fair values of the Company’s crude oil swaps are measured internally using established index prices and other sources. These are based upon, among other things, futures prices and time to maturity.

Asset Retirement and Environmental Obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $288,640, $208,083 and $79,666 during the years ended December 31, 2011, 2010 and 2009, respectively.

10. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began January 1, 2008. The reimbursement amount for indirect expenses is determined by the affiliate’s management based on estimates of office space provided and time devoted to the Company. During the years ended December 31, 2011, 2010 and 2009, the Company incurred total costs of $10,020,059, $7,982,816 and $5,464,190, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $1,896,829, $1,375,267 and $831,519 for the years ended December 31, 2011, 2010 and 2009, respectively. Amounts received until February 26, 2010 were through the related party operator discussed below from the Company’s working interest partners. As of December 31, 2011 and December 31, 2010, the Company owed the administrative services affiliate $769,278 and $372,121, respectively and such amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

 

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Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Operating Services

An entity under common management operated a significant portion of the oil and natural gas properties in which the Company has working and revenue interests. As operator of these properties, this entity was responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which the Company holds an interest. Effective February 26, 2010, the agreement with this entity was terminated and the Company took over as operator of the properties. As of December 31, 2011, the Company did not have a balance payable to this entity. As of December 31, 2010, the Company had an accounts payable-related party balance to this entity of $73,322.

As of December 31, 2011, amounts due to affiliated parties related to property operations consist of drilling and servicing costs of $153,827, prepaid drilling costs of $209,906 and revenues payable of $2,303,184. As of December 31, 2010 amounts due to affiliated parties consist of prepaid drilling costs of $943,390, tubular goods of $68,875 and revenues payable of $266,414. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

As of December 31, 2011 and 2010, amounts due from affiliates related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets is $8,990,273 and $5,611,550, respectively. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

Completion and Well Servicing Services

The Company contracted with an affiliate for certain of its well completion services. Effective August 24, 2011, the affiliate was sold to a non-related third party. While still an affiliate of the Company, the Company was billed $12,511,084, $7,709,051 and $3,261,932 during the years ended December 31, 2011, 2010 and 2009, respectively. Such amounts are capitalized in oil and natural gas properties in the accompanying consolidated balance sheet. At December 31, 2010, approximately $3,061,688 in charges were owed under monthly operations billings and included in accounts payable-related party in the accompanying consolidated balance sheets. At December 31, 2011, the entity was no longer a related party.

Marketing Services

The Company entered into an agreement on March 1, 2009 with an entity under common management that purchases and receives a significant portion of the Company’s oil volumes. The Company’s revenues from the affiliate were $38,178,686, $21,402,799 and $8,815,681 during the years ended December 31, 2011, 2010 and 2009, respectively, and such amounts are included in oil sales in the accompanying consolidated statements of operations. As of December 31, 2011 and 2010, the Company had an accounts receivable-related party balance with the affiliate of $4,132,316 and $2,730,483, respectively, and such amounts are included in the accompanying consolidated balance sheets.

Midland Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. Through December 31, 2011, the Company paid $40,080 under this lease. The current monthly rent under the lease will increase approximately 4% annually on June 1 of each year during the lease term.

 

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Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by an investment fund which is controlled and managed by Wexford. Management believes the credit facility combined with the cash flow generated from operations will be sufficient to sustain the Company’s operations through the end of 2012; however, if additional financing is required management will seek additional sources with could include Wexford.

11. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

In March 2011, the Company began leasing field office space in Midland, Texas from an unrelated party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. In May 2011, the Company began leasing corporate office space in Midland, Texas from an entity controlled by an affiliate of Wexford with a lease term of five years. (See Note 10) Future minimum lease payments for these leases are as follows as of December 31, 2011:

 

2012		$	219,074
2013			222,379
2014			229,566
2015			237,929
2016			185,358
Thereafter			172,600
Total		$	1,266,906

Rent expense for the year ended December 31, 2011 was $74,279.

12. Subsequent Events

The Company has evaluated the period after December 31, 2011 through March 23, 2012, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On February 21, 2012, Wells Fargo & Company announced it had agreed to purchase BNP Paribas’ energy lending business in the United States and that the purchase is subject to regulatory and other approvals and is expected to close in the second quarter of 2012. BNP Paribas is administrative agent, sole book runner and lead arranger of our reserve-based credit facility with 45% of our current borrowing base of $100 million, and a counterparty to certain of our commodity derivatives. The purchase of BNP’s energy lending business by Wells Fargo & Company should not have an effect on the Company’s credit facility.

13. Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The following supplemental unaudited information regarding the oil and natural gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the United States Securities and Exchange Commission (the “SEC”) and the FASB ASU 2010-03, “Extractive Activities-Oil and Gas (Topic 932)”. The

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

reserve reports were prepared in accordance with guidelines established by the SEC and, accordingly, were based on existing economic and operating conditions.

Proved oil and natural gas reserve estimates as of December 31, 2010 and 2009 were prepared by Pinnacle Energy Services, LLC and as of December 31, 2011 were prepared by Ryder Scott Company L.P., both independent petroleum engineers.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

 

		Year Ended December 31,
		2011				2010				2009
Acquisition costs:
Proved properties		$	—			$	—			$	—
Unproved properties			3,213,932				2,393,744				1,816,032
Development costs			72,661,524				47,434,500				16,399,583
Exploration costs			9,574,364				3,394,329				851,036
Capitalized asset retirement costs			288,640				208,083				79,666
Total		$	85,738,460			$	53,430,656			$	19,146,317

Results of Operations from Oil and Natural Gas Producing Activities

The Company’s results of operations from oil, natural gas and natural gas liquid producing activities are presented below for years ended December 31, 2011, 2010 and 2009. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.

 

		Year Ended December 31,
		2011				2010				2009
Oil, natural gas and natural gas liquid sales		$	47,180,802			$	26,441,927			$	12,716,011
Lease operating expenses			(10,345,355	)			(4,588,559	)			(2,366,623	)
Production taxes			(2,333,853	)			(1,346,879	)			(663,068	)
Gathering and transportation			(201,828	)			(105,870	)			(42,091	)
Depreciation, depletion and amortization			(15,178,366	)			(7,373,126	)			(3,155,084	)
Results of operations from oil, natural gas and natural gas liquids		$	19,121,400			$	13,027,493			$	6,489,145

 

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Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Oil and Natural Gas Reserves

The changes in estimated proved reserves are as follows:

 

		Oil (Bbls)				Natural Gas Liquids (Bbls)				Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2009			1,750,440				771,625				2,945,130
Extensions and discoveries			746,019				128,998				478,092
Revisions of previous estimates			26,903,222				6,691,986				24,311,919
Purchase of reserves in place			—				—				—
Production			(168,741	)			(70,384	)			(253,321	)
Sales of reserves in place			—				—				—
As of December 31, 2009			29,230,940				7,522,225				27,481,820
Extensions and discoveries			1,591,094				1,194,217				13,011,377
Revisions of previous estimates			(11,722,263	)			(3,072,486	)			(18,506,630	)
Purchase of reserves in place			—				—				—
Production			(280,721	)			(79,978	)			(323,847	)
Sales of reserves in place			—				—				—
As of December 31, 2010			18,819,050				5,563,978				21,662,720
Extensions and discoveries			1,705,680				448,165				1,824,337
Revisions of previous estimates			(3,366,041	)			(1,162,054	)			(3,454,552	)
Purchase of reserves in place			—				—				—
Production			(441,822	)			(86,815	)			(413,640	)
Sales of reserves in place			—				—				—
As of December 31, 2011			16,716,867				4,763,274				19,618,865
Proved Developed Reserves:
January 1, 2009			1,750,440				771,625				2,945,130
December 31, 2009			1,954,060				591,532				2,453,750
December 31, 2010			3,307,550				1,105,216				4,255,300
December 31, 2011			3,805,291				1,233,319				5,186,941
Proved Undeveloped Reserves:
January 1, 2009			—				—				—
December 31, 2009			27,276,880				6,930,693				25,028,070
December 31, 2010			15,511,500				4,458,762				17,407,420
December 31, 2011			12,911,576				3,529,955				14,431,924

As of December 31, 2011, 2010 and 2009 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

 

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Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward revisions were primarily the result of negative revisions in proved undeveloped wells due to offset well performance; exclusion of proved undeveloped locations that were not scheduled to be drilled within the next five years; and the movement of reserves previously categorized as proved undeveloped to probable reserves due to changes in booking methodology used by our independent petroleum engineers as well as performance of wells in one prospect area.

The Company experienced downward reserve revisions in 2010, due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

The Company experienced upward reserve revisions in 2009, due to the pricing recovery in 2009 and the amendments of ASC 932 in ASU 2010-03.

The increase in 2009 reserves described above had an effect on our depletion and net loss in 2009. The Company is unable to estimate the effect on the 2009 financial statements of the SEC Modernization of the Oil and Gas Reporting Requirement rule that was effective as of December 31, 2009 because a comparative reserve report prepared under the previous rules does not exist.

As of December 31, 2008 all proved undeveloped reserves were noneconomic due to the commodity pricing utilized for the reserve estimate at year end.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” As of December 31, 2011, 2010 and 2009 the standardized measure of discounted future net cash flows are based on the average, first-day-of-the-month price.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. The Company’s investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of the Company’s proved reserves at a given time with those of other oil and gas producing companies than is provided by a comparison of raw proved reserve quantities.

 

		December 31,
		2011				2010				2009
Future cash inflows		$	1,901,127,669			$	1,776,887,010			$	2,040,811,600
Future development costs			(373,750,257	)			(376,204,640	)			(397,076,030	)
Future production costs			(458,939,218	)			(365,712,860	)			(429,507,800	)
Future production taxes			(97,457,261	)			(121,987,210	)			(138,799,710	)
Future net cash flows			970,980,933				912,982,300				1,075,428,060
10% discount to reflect timing of cash flows			(627,533,692	)			(582,624,480	)			(682,509,150	)
Standardized measure of discounted future net cash flows		$	343,447,241			$	330,357,820			$	392,918,910

 

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Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.

 

		December 31,
		2011				2010				2009
		Unweighted Arithmetic Average First-Day-of-the- Month Prices
Oil (per Bbl)		$	93.09			$	77.61			$	58.84
Natural gas (per Mcf)		$	3.91			$	4.14			$	3.64
Natural gas liquids (per Bbl)		$	56.33			$	40.74			$	29.37

The effect of the adoption of the revised SEC rules as of December 31, 2009 with respect to the use of the 12-month unweighted average price caused decreases in reserve volumes and pricing as follows:

 

•

oil volumes of 515,390 Bbls and $18.18 per Bbl;

 

•

natural gas liquids volumes of 130,100 Bbls and $8.85 per Bbl; and

 

•

gas volumes of 537,010 Mcf and $1.84 per Mcf.

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

 

		Year Ended December 31,
		2011				2010				2009
Standardized measure of discounted future net cash flows at the beginning of the period		$	330,357,820			$	392,918,910			$	41,435,980
Sales of oil and natural gas, net of production costs			(34,299,766	)			(20,400,619	)			(9,644,229	)
Purchase of minerals in place			—				—				—
Extensions and discoveries, net of future development costs			69,375,680				52,678,768				18,489,620
Development costs incurred during the period			83,166,092				51,023,970				16,345,261
Net changes in prices and production costs			80,480,005				178,197,726				7,580,209
Changes in estimated future development costs			(76,990,690	)			(23,991,650	)			(409,015,151	)
Revisions of previous quantity estimates			(100,433,225	)			(292,306,238	)			798,975,216
Sales of reserves in place, net of future development costs			—				—				—
Accretion of discount			33,035,782				39,291,891				4,143,598
Net changes in timing of production and other			(41,244,457	)			(47,054,938	)			(75,391,594	)
Standardized measure of discounted future net cash flows at the end of the period		$	343,447,241			$	330,357,820			$	392,918,910

 

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Table of Contents

Report of Independent Certified Public Accountants

Members

Windsor UT LLC

We have audited the accompanying balance sheets of Windsor UT LLC (a Delaware limited liability company) as of December 31, 2011 and 2010, and the related statement of operations, changes in members’ equity and cash flows for the year ended December 31, 2011 and the period from inception (April 28, 2010) to December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Windsor UT LLC as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the year ended December 31, 2011 and the period from inception (April 28, 2010) to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

May 1, 2012

 

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Table of Contents

Windsor UT LLC

Balance Sheets

 

		December 31,
		2011				2010
Assets
Current assets:
Cash and cash equivalents		$	156,733			$	29,536
Accounts receivable-related party			214,633				—
Total current assets			371,366				29,536
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($2,796,065 and $7,144,265 excluded from amortization at December 31,2011 and 2010, respectively)			14,321,344				9,458,667
Accumulated depletion, depreciation and amortization			(198,712	)			—
			14,122,632				9,458,667
Prepaid drilling costs-related party			—				251,715
Total assets		$	14,493,998			$	9,739,918
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	395			$	1,100
Accounts payable–related party			279,988				15,849
Total current liabilities			280,383				16,949
Asset retirement obligations			24,267				14,436
Total liabilities			304,650				31,385
Commitments and contingencies (Note 6)
Members’ equity			14,189,348				9,708,533
Total liabilities and members’ equity		$	14,493,998			$	9,739,918

See accompanying notes to financial statements.

 

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Table of Contents

Windsor UT LLC

Statements of Operations

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Revenues:
Oil sales-related party		$	694,666			$	—
Total revenues			694,666				—
Costs and expenses:
Lease operating expenses			251,824				—
Production taxes			32,016				—
Depreciation, depletion and amortization			198,712				—
General and administrative expenses			37,044				—
Asset retirement obligation accretion expense			1,255				—
Total costs and expenses			520,851				—
Net income		$	173,815			$	—

See accompanying notes to financial statements.

 

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Table of Contents

Windsor UT LLC

Statement of Changes in Members’ Equity

 

		Total members’ equity
Balance at inception (April 28, 2010)		$	—
Contributions			9,708,533
Balance at December 31, 2010			9,708,533
Contributions			4,307,000
Net income			173,815
Balance at December 31, 2011		$	14,189,348

See accompanying notes to financial statements.

 

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Table of Contents

Windsor UT LLC

Statements of Cash Flows

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Cash flows from operating activities:
Net income		$	173,815			$	—
Adjustments to reconcile net income to net cash provided by operating activities:
Asset retirement obligation accretion expense			1,255				—
Depreciation, depletion, and amortization			198,712				—
Changes in operating assets and liabilities:
Accounts receivable-related party			(214,633	)			—
Accounts payable and accrued liabilities			(705	)			1,100
Accounts payable and accrued liabilities-related party			55,102				15,849
Net cash provided by operating activities			213,546				16,949
Cash flows from investing activities:
Additions to oil and natural gas properties-related party			(4,393,349	)			(2,102,413	)
Net cash used in investing activities			(4,393,349	)			(2,102,413	)
Cash flows from financing activities:
Contributions by members			4,307,000				2,115,000
Net cash provided by financing activities			4,307,000				2,115,000
Net increase in cash and cash equivalents			127,197				29,536
Cash and cash equivalents at beginning of period			29,536				—
Cash and cash equivalents at end of period		$	156,733			$	29,536
Supplemental cash flow information
Asset retirement obligation incurred, including changes in estimate		$	8,576			$	14,436
Property contributed		$	—			$	7,593,533

See accompanying notes to financial statements.

 

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Table of Contents

Windsor UT LLC

Notes to Financial Statements

1. Organization

Windsor UT LLC (“the Company”) is a limited liability company formed on April 28, 2010 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company. The Company is wholly owned by investment funds which are controlled and managed by Wexford Capital LP (“Wexford”).

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others. The Company was a development stage enterprise at December 31, 2010.

2. Summary of Significant Accounting Policies

The Company’s financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.

Use of estimates

Certain amounts included in or affecting the Company’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents.

Accounts Receivable

Accounts receivable consist primarily of receivables for oil and natural gas production delivered to purchasers. Those purchasers remit payment for production to the operator of the respective producing properties and the operator, in turn, remits payment to the Company. As discussed in Note 5, the Company’s oil and natural gas properties are contractually operated by an affiliate. Most payments are received within three months after the production date.

 

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Table of Contents

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Accounts receivable are stated at amounts due from purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2011 or 2010.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables and payables. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $26.11 for the year ended December 31, 2011 and because the Company did not have any production in 2010 there was no depletion for the period ended December 31, 2010. Depreciation, depletion and amortization expense for oil and natural gas properties was $198,712 for the year ended December 31, 2011, and there was no expense for the period ended December 31, 2010.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. No impairment on proved oil and natural gas properties was recorded for the periods ended December 31, 2011 or 2010.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2011 and 2010.

Concentrations

During the year period ended December 31, 2011, the Company sold its production to one purchaser. Windsor Midstream LLC, an entity controlled by Wexford, accounted for 100% of the oil revenue. The Company believes there are other crude oil purchasers to whom it would be able to sell its oil if the current purchaser discontinued purchasing from the Company.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as a limited liability company, is not subject to federal income taxes. As appropriate, the taxable income or loss applicable to operations is included in the federal income tax returns of the respective owners and no income tax effect is included in the accompanying financial statements. The Company is subject to margin tax in the state of Texas. During the periods ended December 31, 2011 and 2010, there was no margin tax expense. The Company’s 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2011 and 2010, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the periods ended December 31, 2011 and 2010 there was no interest or penalties associated with uncertain tax positions in the Company’s financial statements.

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on the Company’s financial position, results of operations or cash flow.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on the Company’s financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		December 31,
		2011				2010
Oil and natural gas properties:
Subject to depletion		$	11,525,279			$	2,314,402
Not subject to depletion-acquisition costs
Incurred in 2011			490,007				—
Incurred in 2010			2,306,058				7,144,265
Total not subject to depletion			2,796,065				7,144,265
Gross oil and natural gas properties			14,321,344				9,458,667
Less accumulated depreciation, depletion and amortization			(198,712	)			—
Oil and natural gas properties, net		$	14,122,632			$	9,458,667

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

A reconciliation of the asset retirement obligation is as follows:

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Asset retirement obligation, beginning of period		$	14,436			$	—
Additional liability incurred			8,576				14,436
Accretion expense			1,255				—
Asset retirement obligation, end of period			24,267				14,436
Less current portion			—				—
Asset retirement obligation, long-term		$	24,267			$	14,436

5. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began April 28, 2010. The reimbursement amount for indirect expenses is determined by the affiliate’s management based on estimates of office space provided and time devoted to the Company. During the periods ended December 31, 2011 and 2010, the Company incurred total costs of $90,127 and $12,879, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $57,250 and $14,437 for the periods ended December 31, 2011 and 2010, respectively which were received through the related party operator discussed below. As of December 31, 2011 and December 31, 2010, the Company owed the administrative services affiliate $3,864 and $709, respectively and such amounts are included in accounts payable-related party in the accompanying balance sheets.

Operating Services

An entity under common management operates the oil and natural gas properties in which the Company has working and revenue interests. As operator of these properties, this entity is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties. As of December 31, 2011 and 2010 the Company has an accounts payable balance to this entity of $276,124 and $15,140, respectively.

As of December 31, 2010, $251,715 was prepaid to the operator for prepaid drilling costs and as of December 31, 2011 there were no amounts prepaid for drilling costs to the operator. This amount is included in prepaid drilling costs-related party in the accompanying balance sheets.

Marketing Services

An entity under common management purchases and receives all of the Company’s oil volumes. The Company’s revenues from the affiliate during year ended December 31, 2011 were $694,666. As of December 31, 2011 the Company had an accounts receivable balance with the affiliate of $214,633.

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by investment funds which are controlled and managed by Wexford. Management believes cash flows generated from operations will be sufficient to sustain the Company’s

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

operations through the end of 2012; however, if additional financing is required to continue to develop our properties management will seek additional sources which could include Wexford.

6. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

7. Subsequent Events

The Company has evaluated the period after December 31, 2011 through May 1, 2012 the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

Wexford has agreed in principle to cause all the outstanding equity interests in the Company to be contributed to Windsor Permian LLC, an entity under common control. This contribution will close prior to the initial public offering of Diamondback Energy Inc. who will be the parent of Windsor Permian LLC.

8. Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The following supplemental unaudited information regarding the oil and natural gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the United States Securities and Exchange Commission (the “SEC”) and the FASB ASU 2010-03, “Extractive Activities-Oil and Gas (Topic 932)”. The reserve reports were prepared in accordance with guidelines established by the SEC and, accordingly, were based on existing economic and operating conditions.

Proved oil and natural gas reserve estimates as of December 31, 2010 were prepared by Pinnacle Energy Services, LLC and as of December 31, 2011 were prepared by Ryder Scott Company L.P., both independent petroleum engineers.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

 

		Year Ended December 31,
		2011				2010
Acquisition costs:
Proved properties		$	—			$	—
Unproved properties			490,029				7,536,554
Development costs			2,712,638				1,381,594
Exploration costs			1,651,434				526,083
Capitalized asset retirement costs			8,576				14,436
Total		$	4,862,677			$	9,458,667

Results of Operations from Oil and Natural Gas Producing Activities

The Company’s results of operations from oil and natural gas producing activities are presented below for year ended December 31, 2011. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to net operating results of our oil, natural gas and natural gas liquids operations.

 

		Year Ended December 31, 2011
Oil sales		$	694,666
Lease operating expenses			(251,824	)
Production taxes			(32,016	)
Depreciation, depletion and amortization			(198,712	)
Results of operations from oil, natural gas and natural gas liquids		$	212,114

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Oil and Natural Gas Reserves

The changes in estimated proved reserves are as follows:

 

		Oil (Bbls)				Natural  Gas Liquids (Bbls)				Natural  Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of Inception (April 28, 2010)
Extensions and discoveries			811,110				268,989				1,032,360
Revisions of previous estimates			—				—				—
Purchase of reserves in place			—				—				—
Production			—				—				—
Sales of reserves in place			—				—				—
As of December 31, 2010			811,110				268,989				1,032,360
Extensions and discoveries			93,495				18,374				59,855
Revisions of previous estimates			486,613				(1,076	)			(159,615	)
Purchase of reserves in place			—				—				—
Production			(7,611	)			—				—
Sales of reserves in place			—				—				—
As of December 31, 2011			1,383,607				286,287				932,600
Proved Developed Reserves:
December 31, 2010			63,910				21,215				81,420
December 31, 2011			143,808				30,392				99,004
Proved Undeveloped Reserves:
December 31, 2010			747,200				247,774				950,940
December 31, 2011			1,239,799				255,895				833,596

As of December 31, 2011 and 2010 reserves were computed using the trailing 12-month unweighted average of the first-day-of-the-month prices, in accordance with the SEC guidelines applicable to reserves estimates.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” As of December 31, 2011 and 2010 the standardized measure of discounted future net cash flows are based on the trailing 12-month unweighted average, first-day-of-the-month prices.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

The Company’s investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of the Company’s proved reserves at a given time with those of other oil and gas producing companies than is provided by a comparison of raw proved reserve quantities.

 

		December 31,
		2011				2010
Future cash inflows		$	148,561,297			$	79,406,680
Future development costs			(36,600,000	)			(22,100,000	)
Future production costs			(38,872,203	)			(19,203,120	)
Future production taxes			(7,410,909	)			(4,102,820	)
Future net cash flows			65,678,185				34,000,740
10% discount to reflect timing of cash flows			(47,669,824	)			(25,357,600	)
Standardized measure of discounted future net cash flows		$	18,008,361			$	8,643,140

In the table below the average price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.

 

		December 31,
		2011				2010
Oil (per Bbl)		$	92.99			$	78.76
Natural gas (per Mcf)		$	3.92			$	4.26
Natural gas liquids (per Bbl)		$	56.74			$	41.34

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

 

		Year Ended December 31,
		2011				2010
Standardized measure of discounted future net cash flows at the beginning of the period		$	8,643,140			$	—
Sales of oil and natural gas, net of production costs			(410,826	)			—
Net changes in prices and production costs			1,883,765				—
Purchase of minerals in place			—				—
Development costs incurred during the period			4,364,072				1,907,677
Extensions and discoveries, net of future development costs			4,195,434				6,735,463
Change in estimated future development costs			(5,864,072	)			—
Revisions of previous quantity estimates			1,899,993				—
Sales of reserves in place			—				—
Accretion of discount			864,314				—
Net changes in timing of production and other			2,432,541				—
Standardized measure of discounted future net cash flows at the end of the period		$	18,008,361			$	8,643,140

 

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Report of Independent Certified Public Accountants

Board of Directors

Gulfport Energy Corporation

We have audited the accompanying statements of revenues and direct operating expenses of working and revenue interests of certain oil and gas properties (the “Properties”) owned by Gulfport Energy Corporation (“Gulfport”) for the years ended December 31, 2011 and 2010. These statements are the responsibility of Gulfport’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

As described in Note A, the accompanying statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete financial presentation.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses as described in Note A for the years ended December 31, 2011 and 2010.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

April 24, 2012

 

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CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

 

		Year Ended December 31,
		2011				2010
Revenues:
Oil and gas sales		$	23,052,000			$	14,088,000
Direct operating expenses
Lease operating expenses			5,484,000				2,375,000
Production taxes			1,276,000				806,000
Total direct operating expenses			6,760,000				3,181,000
Revenues in excess of direct operating expenses		$	16,292,000			$	10,907,000

 

See accompanying notes to statements of revenues and direct operating expenses.

 

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CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

NOTE A—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses of working and revenue interests of certain oil and natural gas properties located in the Permian Basin of West Texas (the “Properties”) owned by Gulfport Energy Corporation (“Gulfport”) for the years ended December 31, 2011 and 2010.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Gulfport. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense as these costs may not be comparable to the expenses expected to be incurred on a prospective basis.

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not readily available on an individual property basis. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

NOTE B—SIGNIFICANT ACCOUNTING POLICIES

Use of estimates

The preparation of the accompanying statements in conformity with generally accepted accounting principles requires making estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. The estimates include oil and gas revenue accruals and reserve quantities. It is emphasized that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Actual results could materially differ from these estimates.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable.

NOTE C—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The proved oil and gas reserves attributable to the Properties consist of the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The weighted average prices used for reserve report purposes are $96.19 and $4.12 for December 31, 2011 and $79.43 and $4.38 at December 31, 2010, adjusted for transportation fees and regional price differentials, for oil and natural gas reserves, respectively. The following estimates of proved reserves have been made by the independent engineering firms of Ryder Scott Company L.P. and Pinnacle Energy Services, LLC based on the Gulfport’s net revenue interest for 2011 and 2010, respectively.

Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and

 

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CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010-(CONTINUED)

 

geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

 

		2011								2010
		Oil (MBbls)				Gas (MMcf)				Oil (MBbls)				Gas (MMcf)
Proved Reserves
Beginning of the period			12,465				11,926				9,763				10,894
Purchases in oil and gas reserves in place			—				—				3,566				3,341
Extensions and discoveries			981				992				3,701				3,512
Revisions of prior reserve estimates			(2,302	)			(599	)			(4,365	)			(5,565	)
Current production			(267	)			(272	)			(200	)			(256	)
End of period			10,877				12,047				12,465				11,926
Proved developed reserves			2,803				3,050				2,634				3,048
Proved undeveloped reserves			8,074				8,997				9,831				8,878

Proved developed reserves as of January 1, 2010 were 1,560 MBbls of oil and 2,009 MMcf of gas and proved undeveloped reserves as of January 1, 2010 were 8,203 MBbls of oil and 8,885 MMcf of gas.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows is computed by applying unweighted average first-of-the-month prices of oil and natural gas, adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on certain prevailing economic conditions) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Income taxes are excluded because the property interests included represent only a portion of a business for which income taxes are not estimable.

 

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CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010-(CONTINUED)

 

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value would also take into account, among other things, probable and possible reserves, anticipated future oil and natural gas prices, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

 

		Year ended December 31,
		2011				2010
Future cash flows		$	960,918,000			$	902,221,000
Future development and abandonment costs			(236,336,000	)			(196,265,000	)
Future production costs			(166,899,000	)			(208,210,000	)
Future production taxes			(50,235,000	)			(46,605,000	)
Future net cash flows			507,448,000				451,141,000
10% discount to reflect timing of cash flows			(305,160,000	)			(289,035,000	)
Standardized measure of discounted future net cash flows		$	202,288,000			$	162,106,000

Changes in standardized measure of discounted future net cash flows

 

		Year ended December 31,
		2011				2010
Sales and transfers of oil and gas produced, net of production costs		$	(16,292,000	)		$	(10,907,000	)
Net changes in prices, production costs and development costs			48,089,000				37,212,000
Acquisition of oil and gas reserves in place			—				81,901,000
Extensions and discoveries			29,432,000				84,971,000
Revisions of previous quantity estimates, less related production costs			(71,088,000	)			(99,257,000	)
Accretion of discount			16,211,000				9,143,000
Change in production rates and other			33,830,000				(32,389,000	)
Total change in standardized measure of discounted future net cash flows		$	40,182,000			$	70,674,000

 

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Dealer Prospectus Delivery Obligation

Until                     , 2012 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

 

 

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth the fees and expenses in connection with the issuance and distribution of the securities being registered hereunder. Except for the SEC registration fee and FINRA filing fee, all amounts are estimates.

 

SEC registration fee		$	5,730
FINRA filing fee			*
NASDAQ Global Market listing fee			*
Accounting fees and expenses			*
Legal fees and expenses			*
Blue Sky fees and expenses (including counsel fees)			*
Printing and Engraving expenses			*
Transfer Agent and Registrar fees and expenses			*
Miscellaneous expenses			*
Total		$	*

 

*	To be completed by amendment.

Item 14. Indemnification of Directors and Officers.

Limitation of Liability

Section 102(b)(7) of the Delaware General Corporation Law, or the DGCL, permits a corporation, in its certificate of incorporation, to limit or eliminate, subject to certain statutory limitations, the liability of directors to the corporation or its stockholders for monetary damages for breaches of fiduciary duty, except for liability:

 

•

for any breach of the director’s duty of loyalty to the company or its stockholders;

 

•

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

•

in respect of certain unlawful dividend payments or stock redemptions or repurchases; and

 

•

for any transaction from which the director derives an improper personal benefit.

In accordance with Section 102(b)(7) of the DGCL, Section 9.1 of our certificate of incorporation provides that that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

If the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our certificate of incorporation, the liability of our directors to us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our certificate of incorporation limiting or eliminating the liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.

 

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Indemnification

Section 145 of the DGCL permits a corporation, under specified circumstances, to indemnify its directors, officers, employees or agents against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlements actually and reasonably incurred by them in connection with any action, suit or proceeding brought by third parties by reason of the fact that they were or are directors, officers, employees or agents of the corporation, if such directors, officers, employees or agents acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reason to believe their conduct was unlawful. In a derivative action, i.e., one by or in the right of the corporation, indemnification may be made only for expenses actually and reasonably incurred by directors, officers, employees or agents in connection with the defense or settlement of an action or suit, and only with respect to a matter as to which they shall have acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification shall be made if such person shall have been adjudged liable to the corporation, unless and only to the extent that the court in which the action or suit was brought shall determine upon application that the defendant directors, officers, employees or agents are fairly and reasonably entitled to indemnity for such expenses despite such adjudication of liability

Our certificate of incorporation provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former directors and officers, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney’s fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our certificate of incorporation will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.

The right to indemnification conferred by our certificate of incorporation is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately determined that such person is not entitled to be indemnified for such expenses under our certificate of incorporation or otherwise.

The rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our certificate of incorporation may have or hereafter acquire under law, our certificate of incorporation, our bylaws, an agreement, vote of stockholders or disinterested directors, or otherwise.

Any repeal or amendment of provisions of our certificate of incorporation affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our certificate of incorporation also permits us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our certificate of incorporation.

 

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Our bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our certificate of incorporation. In addition, our bylaws provide for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.

Any repeal or amendment of provisions of our bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision.

We will enter into indemnification agreements with each of our current directors and executive officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Under the Underwriting Agreement, the underwriters are obligated, under certain circumstances, to indemnify directors and officers of the registrant against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or the Securities Act. Reference is made to the form of Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement.

Item 15. Recent Sales of Unregistered Securities.

In exchange for the contribution by DB Holdings of all of the outstanding equity interests in Windsor Permian to us prior to the completion of this offering, we will issue          shares of our common stock to DB Holdings. In addition, prior to the closing of this offering, we will issue shares of our common stock to Gulfport in connection with the Gulfport contribution.

The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.

Item 16. Exhibits and Financial Statement Schedules.

(A) Exhibits:

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Incorporation of the Company.
3.2***		Form of proposed Amended and Restated Certificate of Incorporation to be effective immediately upon the closing of the offering made pursuant to this registration statement.
3.3*		Bylaws of the Company.
3.4***		Form of proposed Bylaws to be effective immediately upon the closing of the offering made pursuant to this registration statement.

 

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Exhibit Number		Number Description
4.1***		Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company.
4.2**		Registration Rights Agreement by and among the Company and DB Energy Holdings LLC.
4.3**		Form of Investor Rights Agreement by and between the Company and Gulfport Energy Corporation.
5.1***		Opinion of Akin Gump Strauss Hauer & Feld LLP.
10.1*		Credit Agreement, dated as of October 15, 2010, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2*		First Amendment to Credit Agreement, dated as of January 31, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3*		Second Amendment to Credit Agreement, dated as of August 4, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.4*		Third Amendment to Credit Agreement, dated as of October 14, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.5*		Fourth Amendment to Credit Agreement, dated as of December 30, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.6**		Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC.
10.7***		Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.8**		Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.9**		Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.10**		Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.11**		Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.12***†		Equity Incentive Plan.
10.13***†		Form of Stock Option Agreement.
10.14***†		Form of Restricted Stock Agreement.
10.15***†		Form of Director and Officer Indemnification Agreement.
10.16**		Form of Advisory Services Agreement by and between Diamondback Energy, Inc. and Wexford Capital LP.
10.17***		Contribution Agreement by and between the Company and DB Energy Holdings LLC.
10.18**		Contribution Agreement, dated May 7, 2012, by and between the Company and Gulport Energy Corporation.
10.19**		Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC.
10.20**		Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company.
10.21**		Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC.
10.22**		Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC.

 

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Table of Contents

Exhibit Number		Number Description
21.1***		List of Significant Subsidiaries of the Company.
23.1**		Consent of Grant Thornton LLP.
23.2**		Consent of Pinnacle Energy Services, LLC.
23.3**		Consent of Ryder Scott Company.
23.4***		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
24.1*		Power of Attorney.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

(B) Financial Statement Schedules.

All schedules are omitted because the required information is (i) not applicable, (ii) not present in amounts sufficient to require submission of the schedule or (iii) included in our financial statements and the accompanying notes included in the prospectus to this Registration Statement.

Item 17. Undertakings.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification by the Registrant for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, State of Texas, on May 7, 2012.

 

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on May 7, 2012.

 

Signature		Title
/s/ Travis D. Stice Travis D. Stice		Chief Executive Officer (Principal Executive Officer)
/s/ Teresa L. Dick Teresa L. Dick		Chief Financial Officer (Principal Financial and Accounting Officer)
* Steven E. West		Director

 

* By:		/s/ Travis D. Stice
		Travis D. Stice
		Attorney-in-Fact

 

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Table of Contents

EXHIBIT INDEX

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Incorporation of the Company.
3.2***		Form of proposed Amended and Restated Certificate of Incorporation to be effective immediately upon the closing of the offering made pursuant to this registration statement.
3.3*		Bylaws of the Company.
3.4***		Form of proposed Bylaws to be effective immediately upon the closing of the offering made pursuant to this registration statement.
4.1***		Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company.
4.2**		Registration Rights Agreement by and among the Company and DB Energy Holdings LLC.
4.3**		Form of Investor Rights Agreement by and between the Company and Gulfport Energy Corporation.
5.1***		Opinion of Akin Gump Strauss Hauer & Feld LLP.
10.1*		Credit Agreement, dated as of October 15, 2010, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2*		First Amendment to Credit Agreement, dated as of January 31, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3*		Second Amendment to Credit Agreement, dated as of August 4, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.4*		Third Amendment to Credit Agreement, dated as of October 14, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.5*		Fourth Amendment to Credit Agreement, dated as of December 30, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.6**		Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC.
10.7***		Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.8**		Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.9**		Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.10**		Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.11**		Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.12***†		Equity Incentive Plan.
10.13***†		Form of Stock Option Agreement.
10.14***†		Form of Restricted Stock Agreement.
10.15***†		Form of Director and Officer Indemnification Agreement.
10.16**		Form of Advisory Services Agreement by and between Diamondback Energy, Inc. and Wexford Capital LP.

 

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Exhibit Number		Number Description
10.17***		Contribution Agreement by and between the Company and DB Energy Holdings LLC.
10.18**		Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation.
10.19**		Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC.
10.20**		Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company.
10.21**		Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC.
10.22**		Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC.
21.1***		List of Significant Subsidiaries of the Company.
23.1**		Consent of Grant Thornton LLP.
23.2**		Consent of Pinnacle Energy Services, LLC.
23.3**		Consent of Ryder Scott Company.
23.4***		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
24.1*		Power of Attorney.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

 

E-2

Exhibit 4.2

[FORM OF]

REGISTRATION RIGHTS AGREEMENT

Dated as of             , 2012

by and between

DIAMONDBACK ENERGY, INC.

and

DB ENERGY HOLDINGS LLC

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				Page
Section 1.		Definitions			1
Section 2.		Demand Registrations			3
Section 3.		Piggyback Registrations			6
Section 4.		Obligations of the Company			7
Section 5.		Registration Expenses			11
Section 6.		Indemnification			11
Section 7.		Rules 144 and 144A			14
Section 8.		Underwritten Registrations			14
Section 9.		Covenants of Holders			15
Section 10.		Miscellaneous			15

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REGISTRATION RIGHTS AGREEMENT

THIS REGISTRATION RIGHTS AGREEMENT (the “Agreement”) is made and entered into as of             , 2012, by and between Diamondback Energy, Inc., a Delaware corporation (the “Company”), and DB Energy Holdings LLC, a Delaware limited liability company (the “Stockholder”).

WHEREAS, the Company was formed in December 2011 in contemplation of an initial public offering of common stock of the Company (“Common Stock Offering”).

WHEREAS, the Stockholder will be issued [            ] shares (the “Shares”) of Common Stock (as defined below), all of which were validly issued, fully paid and non-assessable, pursuant to the Contribution Agreement (as defined below).

WHEREAS, the parties hereto desire to enter into this Agreement to govern certain of their rights, duties and obligations relating to registration of the Registrable Securities (as defined below).

NOW, THEREFORE, for good, valuable and binding consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, now agree as follows:

STATEMENT OF AGREEMENT

Section 1. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

“Agreement” has the meaning set forth in the introductory paragraph of this Agreement.

“Affiliate” means, with respect to any Person, a Person that directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with the specified Person.

“Commission” means the United States Securities and Exchange Commission or any other United States federal agency at the time administering the Securities Act.

“Common Stock” means the Company’s common stock, par value $0.01 per share, or any other shares of capital stock or other securities of the Company into which such shares of Common Stock shall be reclassified or changed, including by reason of a merger, consolidation, reorganization or recapitalization. If the Common Stock has been so reclassified or changed, or if the Company pays a dividend or makes a distribution on the Common Stock in shares of capital stock, or subdivides (or combines) its outstanding shares of Common Stock into a greater (or smaller) number of shares of Common Stock, a share of Common Stock shall be deemed to be such number of shares of stock and amount of other securities to which a holder of a share of Common Stock outstanding immediately prior to such change, reclassification, exchange, dividend, distribution, subdivision or combination would be entitled.

“Common Stock Offering” has the meaning set forth in the recitals of this Agreement.

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“Contribution Agreement” means that certain Contribution Agreement by and between the Company and the Stockholder dated as of             , 2012, pursuant to which the Stockholder contributed all of the outstanding equity interests in Windsor Permian LLC to the Company in exchange for the shares of Common Stock.

“Controlling,” “Controlled by” and “under common Control with” refer to the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ownership of voting securities, any equity interest, or a membership interest in a non-stock corporation; by contract; by power granted in bylaws or similar governing documents; or otherwise. Without limiting the foregoing, any ownership interest greater than fifty percent (50%) for purposes hereof constitutes “Control.”

“Delay Period” has the meaning set forth in Section 4(a) of this Agreement.

“Demand Notice” has the meaning set forth in Section 2(a) of this Agreement.

“Demand Registration” has the meaning set forth in Section 2(a) of this Agreement.

“Exchange Act” means the United States Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder.

“Gulfport Investor Rights Agreement” means that certain Investor Rights Agreement by and between the Company and Gulfport Energy Corporation dated as of the date hereof.

“Holder(s)” means a person who owns Registrable Securities and is either (i) a Stockholder or a Permitted Transferee of a Stockholder that has agreed to be bound by the terms of this Agreement as if such Person were a Stockholder, (ii) upon the death of any Holder, the executor of the estate of such Holder or such Holder’s heirs, devisees, legatees or assigns or (iii) upon the disability of any Holder, any guardian or conservator of such Holder.

“Interruption Period” has the meaning set forth in the last paragraph in Section 4(b).

“Losses” has the meaning set forth in Section 6(a) of this Agreement.

“Misstatement/Omission” has the meaning set forth in Section 6(a) of this Agreement.

“Permitted Transferee” means any Person to whom the rights under this Agreement have been assigned in accordance with the provisions of Section 10(d) of this Agreement.

“Person” means any natural person, corporation, partnership, firm, association, trust, government, governmental agency, limited liability company or any other entity, whether acting in an individual, fiduciary or other capacity.

“Piggyback Registration” has the meaning set forth in Section 3(a) of this Agreement.

“Prospectus” means the prospectus included in any Registration Statement, as amended or supplemented by any prospectus supplement, with respect to the terms of the offering of any portion of the Registrable Securities covered by such Registration Statement, and all other amendments and supplements to the Prospectus, including post-effective amendments, and all material incorporated by reference or deemed to be incorporated by reference in such prospectus.

 

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“Registrable Securities” means (i) the Shares, (ii) any other shares of Common Stock that may be acquired by a Holder prior to or after the closing of the Common Stock Offering and (iii) any shares of Common Stock issuable pursuant to any rights to acquire Common Stock held by a Holder prior to or after the closing of the Common Stock Offering. If as a result of any reclassification, stock dividends or stock splits or in connection with a combination of shares, recapitalization, merger, consolidation or other reorganization or other transaction or event, any capital stock, evidence of indebtedness, warrants, options, rights or other securities (collectively “Other Securities”) are issued or transferred to a Holder in respect of Registrable Securities held by the Holder, references herein to Registrable Securities shall be deemed to include such Other Securities. As to any particular Registrable Securities, such securities will cease to be Registrable Securities when (i) they have been distributed to the public pursuant to an offering registered under the Securities Act, or may legally be distributed to the public in one transaction pursuant to Rule 144 under the Securities Act, (ii) they have been distributed to the public pursuant to Rule 144 (or any successor provision) under the Securities Act, or (iii) they have been sold to any Person to whom the rights under this Agreement are not assigned in accordance with this Agreement.

“Registration Statement” means any registration statement under the Securities Act of the Company that covers any of the Registrable Securities, including the related Prospectus, amendments and supplements to such registration statement or Prospectus, including pre- and post-effective amendments, all exhibits, and all materials incorporated by reference or deemed to be incorporated by reference in such registration statement or Prospectus.

“Securities Act” means the United States Securities Act of 1933, as amended, and the rules and regulations of the Commission promulgated thereunder.

“Shares” has the meaning set forth in the recitals of this Agreement.

“Stockholder” has the meaning set forth in the introductory paragraph of this Agreement.

Section 2. Demand Registrations.

(a) Right to Demand. Upon the terms and subject to the conditions of this Agreement, Holders of at least a majority of the aggregate amount of outstanding Registrable Securities shall have the right, by written notice (the “Demand Notice”) given to the Company, to request the Company to register under and in accordance with the provisions of the Securities Act all or part of the Registrable Securities designated by such Holders (a “Demand Registration”). Upon receipt of any such Demand Notice, the Company will promptly notify all other Holders of the receipt of such Demand Notice and allow them the opportunity to include Registrable Securities in the proposed registration by giving notice to the Company within five days after the Holder receives such notice; provided, however, that Holders joining in a proposed registration pursuant to this sentence shall not be deemed to have exercised a Demand Registration for purposes of Section 2(b) hereof and such Holders shall be included in such registration on the basis set forth in Section 2(h) hereof. The Company shall not be required to register any Registrable Securities under this Section 2 unless the anticipated aggregate offering price to the public for any such offering of the Registrable Securities included in such Demand Notice is expected to be at least $1 million.

 

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(b) Number of Demand Registrations. Upon the terms and subject to the conditions of this Agreement, Holders shall be entitled to have three Demand Registrations effected. A Demand Registration shall not be deemed to be effected and shall not count as a Demand Registration of any Person (i) if a Registration Statement with respect thereto shall not have become effective under the Securities Act and remained effective (A) for at least 180 days (excluding any Interruption Period or Delay Period) in the case of a Demand Registration that is not on a Form S-3 or other comparable form or (B) for at least two years (excluding any Interruption Period or Delay Period) in the case of a Demand Registration on Form S-3 or other comparable form, or until the completion of the distribution of the Registrable Securities thereunder, whichever is earlier (including, without limitation, because of withdrawal of such Registration Statement by the Holders pursuant to Section 2(f) hereunder), (ii) if, after it has become effective, such registration is interfered with for any reason by any stop order, injunction or other order or requirement of the Commission or any governmental authority, or as a result of the initiation of any proceeding for such stop order by the Commission through no fault of the Holders and the result of such interference is to prevent the Holders from disposing of such Registrable Securities proposed to be sold in accordance with the intended methods of disposition, or (iii) if the conditions to closing specified in the purchase agreement or underwriting agreement entered into in connection with any underwritten offering shall not be satisfied or waived with the consent of the Holders of a majority in number of the Registrable Securities to be included in such Demand Registration, other than as a result of any breach by the Holders or any underwriter of its obligations thereunder or hereunder.

(c) Registration Statement. Subject to paragraph (a) above, as soon as practicable, but in any event within 45 days of the date on which the Company first receives one or more Demand Notices pursuant to Section 2(a) hereof, the Company shall file with the Commission a Registration Statement on the appropriate form for the registration and sale of the total number of Registrable Securities specified in such Demand Notice, together with the number of Registrable Securities requested to be included in the Demand Registration by other Holders, in accordance with the intended method or methods of distribution specified by the Holders in such Demand Notice. The Company shall use its reasonable best efforts to cause such Registration Statement to be declared effective by the Commission as soon as reasonably practicable.

(d) Amendments; Supplements. Subject to Section 4(a), upon the occurrence of any event that would cause the Registration Statement (A) to contain a material misstatement or omission or (B) to be not effective and usable for resale of Registrable Securities during the period that such Registration Statement is required to be effective and usable, the Company shall file an amendment to the Registration Statement as soon as reasonably practicable if the Registration Statement is not on Form S-3 or another comparable form and such misstatement or omission is not corrected as soon as reasonably practicable by incorporation by reference, in the case of clause (A), correcting any such misstatement or omission and, in the case of either clause (A) or (B), use its reasonable best efforts to cause such amendment to be declared effective and such Registration Statement to become usable as soon as reasonably practicable thereafter.

 

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(e) Effectiveness. The Company agrees to use its reasonable best efforts to keep any Registration Statement filed pursuant to this Section 2 continuously effective and usable for the sale of Registrable Securities until the earlier of (i) (a) in the case of a Demand Registration for delayed or continuous offerings of Registrable Securities filed on Form S-3 or another comparable form, two years after the date on which the Commission declares such Registration Statement effective (excluding any Interruption Period or Delay Period) or (b) in the case of a Demand Registration that is not on Form S-3 or another comparable form, 180 days from the date on which the Commission declares such Registration Statement effective (excluding any Interruption Period or Delay Period) and (ii) the date on which there are no longer any Registrable Securities.

(f) Holders Withdrawal. Holders of a majority in number of the Registrable Securities to be included in a Demand Registration pursuant to this Section 2 may, at any time prior to the effective date of the Registration Statement in respect thereof, revoke such request by providing a written notice to the Company to such effect.

(g) Preemption of Demand Registration. Notwithstanding anything to the contrary contained herein, after receiving a written request for a Demand Registration, the Company may elect to effect an underwritten primary registration in lieu of the Demand Registration if the Company’s Board of Directors believes that such primary registration would be in the best interests of the Company. If the Company so elects to effect a primary registration, the Company shall give prompt written notice (which shall be given not later than 20 days after the date of the Demand Notice) to all Holders of its intention to effect such a registration and shall afford the Holders the rights contained in Section 3 with respect to Piggyback Registrations. In the event that the Company so elects to effect a primary registration after receiving a request for a Demand Registration, the Company shall use its reasonable best efforts to have the Registration Statement declared effective by the Commission as soon as reasonably practicable. In addition, the request for a Demand Registration shall be deemed to have been withdrawn and such primary registration shall not be deemed to be a Demand Registration.

(h) Priority on Demand Registrations. If a Demand Registration is an underwritten offering and includes securities for sale by the Company, and the managing underwriter (such underwriter to be chosen by Holders of a majority of the Registrable Securities included in such registration, subject to the Company’s reasonable approval) advises the Company, in writing, that, in its good faith judgment, the number of securities requested to be included in such registration exceeds the number which can be sold in such offering without materially and adversely affecting the marketability of the offering, then the Company will include in any such registration the maximum number of shares that the managing underwriter advises the Company can be sold in such offering allocated as follows: (i) first, the Registrable Securities requested to be included in such registration by the initiating Holders and securities of other Holders of Registrable Securities and holders of Registrable Securities (as defined in the Gulfport Investor Rights Agreement), with all such securities to be included on a pro rata basis (or in such other proportion mutually agreed among such Holders) based on the amount of securities requested to be included therein and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriter as aforesaid, the securities that the Company proposes to sell together with such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed upon

 

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among the Company and such other holders) based on the amount of securities requested to be included therein. If the initiating Holders are not allowed to register all of the Registrable Securities requested to be included by such Holders because of allocations required by this section, such initiating Holders shall not be deemed to have exercised a Demand Registration for purposes of Section 2(b).

Section 3. Piggyback Registrations.

(a) Right to Piggyback Registrations. Whenever the Company or another party having registration rights proposes that the Company register any of the Company’s equity securities under the Securities Act (other than a registration on Form S-4 relating solely to a transaction described in Rule 145 of the Securities Act or a registration on Form S-8 or any successor forms thereto), whether or not for sale for the Company’s own account, the Company will give prompt written notice of such proposed filing to all Holders at least 15 days before the anticipated filing date. Such notice shall offer such Holders the opportunity to register such amount of Registrable Securities as they shall request (a “Piggyback Registration”). Subject to Section 3(b) hereof, the Company shall include in each such Piggyback Registration all Registrable Securities with respect to which the Company has received written requests for inclusion therein within 10 days after such notice has been given by the Company to the Holders. If the Registration Statement relating to the Piggyback Registration is for an underwritten offering, such Registrable Securities shall be included in the underwriting on the same terms and conditions as the securities otherwise being sold through the underwriters. Each Holder shall be permitted to withdraw all or part of the Registrable Securities from a Piggyback Registration at any time prior to the effective time of such Piggyback Registration.

(b) Priority on Piggyback Registrations. If a Piggyback Registration is an underwritten offering by or through one or more underwriters of recognized standing and the managing underwriters advise the party or parties initiating such offering in writing (a copy of which writing shall be provided to the Holders) that in their good faith judgment the number of securities requested to be included in such registration exceeds the number which can be sold in such offering without materially and adversely affecting the marketability of the offering, then any such registration shall include the maximum number of shares that such managing underwriters advise can be sold in such offering allocated as follows: (x) if the Company has initiated such offering, (i) first, the securities the Company proposes to sell, and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriters as aforesaid, (A) the Registrable Securities to be included in such registration by the Holders and the holders of Registrable Securities (as defined in the Gulfport Investor Rights Agreement), with all such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed among the Holders and such other holders), based on the amount of Registrable Securities and other securities requested to be included therein, and then, if any additional securities may be included (B) to such additional securities on a pro rata basis (or in such other proportion mutually agreed among them), (y) if a holder of Registrable Securities (as defined in the Gulfport Investor Rights Agreement) has initiated such offering (i) first, the securities the holders under the Gulfport Investor Rights Agreement propose to sell together with the securities the Holders of Registrable Securities hereunder propose to sell on a pro rata basis (or in such other proportion mutually agreed upon among such holders and the Holders), based on the amount of securities requested to be included

 

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therein and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriters as aforesaid, all such other securities on a pro rata basis (or in such other proportion mutually agreed upon among such other holders) based on the amount of securities requested to be included therein, and (z) if a party other than the Company or a holder under the Gulfport Investor Rights Agreement initiated such offering, securities proposed to be sold by the Company, and the Registrable Securities to be included in such registration by the Holders, with such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed among the Company, the Holders and such other holders), based on the amount of Registrable Securities and other securities requested to be included therein.

Section 4. Obligations of the Company.

(a) Delay Period. Notwithstanding the foregoing, the Company shall have the right to delay the filing of any Registration Statement otherwise required to be prepared and filed by the Company pursuant to Sections 2 or 3, or to suspend the use of any Registration Statement, for a period not in excess of 60 consecutive calendar days (a “Delay Period”) if (i) the Board of Directors of the Company by written resolution determines that filing or maintaining the effectiveness of such Registration Statement would have a material adverse effect on the Company or the holders of its capital stock in relation to any material acquisition or disposition, financing or other corporate transaction or (ii) the Board of Directors of the Company by written resolution determines in good faith that the filing of a Registration Statement or maintaining the effectiveness of a current Registration Statement would require disclosure of material information that the Company has a valid business purpose for retaining as confidential at such time. The Company shall not be entitled to exercise a Delay Period more than one time in any 12-month period.

(b) Registration Procedures. Whenever the Company is required to register Registrable Securities pursuant to Sections 2 or 3 hereof, the Company will use its reasonable best efforts to effect the registration to permit the sale of such Registrable Securities in accordance with the intended method or methods of disposition thereof, and pursuant thereto the Company will as expeditiously as possible:

(1) prepare and file with the Commission a Registration Statement with respect to such Registrable Securities as prescribed by Sections 2 or 3 on a form available for the sale of the Registrable Securities by the holders thereof in accordance with the intended method or methods of distribution thereof and use its reasonable best efforts to cause each such Registration Statement to become and remain effective within the time periods and otherwise as provided herein;

(2) prepare and file with the Commission such amendments (including post-effective amendments) to the Registration Statement and such supplements to the Prospectus as may be necessary to keep such Registration Statement effective within the time periods and otherwise as provided herein and to comply with the provisions of the Securities Act with respect to the disposition of all securities covered by such Registration Statement until such time as all of such securities have been disposed of in accordance with the intended methods of disposition by the seller or sellers thereof set forth in such Registration Statement, except as otherwise expressly provided herein;

 

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(3) furnish to each selling Holder of Registrable Securities covered by a Registration Statement and to each underwriter, if any, such number of copies of such Registration Statement, each amendment and post-effective amendment thereto, the Prospectus included in such Registration Statement (including each preliminary prospectus and any supplement to such Prospectus and any other prospectus filed under Rule 424 of the Securities Act), in each case including all exhibits, and such other documents as such Holder may reasonably request in order to facilitate the disposition of the Registrable Securities owned by such Holder or to be disposed of by such underwriter (the Company hereby consenting to the use in accordance with all applicable law of each such Registration Statement (or amendment or post-effective amendment thereto) and each such Prospectus (or preliminary prospectus or supplement thereto) by each such Holder and the underwriters, if any, in connection with the offering and sale of the Registrable Securities covered by such Registration Statement or Prospectus);

(4) use its reasonable best efforts to register or qualify and, if applicable, to cooperate with the selling Holders, the underwriters, if any, and their respective counsel in connection with the registration or qualification (or exemption from such registration or qualification) of, the Registrable Securities for offer and sale under the securities or blue sky laws of such jurisdictions as any selling Holder or managing underwriters (if any) shall reasonably request, to keep each such registration or qualification (or exemption therefrom) effective during the period such Registration Statement is required to be kept effective as provided herein and to do any and all other acts or things necessary or advisable to enable the disposition in such jurisdictions of the securities covered by the applicable Registration Statement; provided, however, that the Company will not be required to (i) qualify generally to do business in any jurisdiction where it would not otherwise be required to qualify but for this paragraph or (ii) consent to general service of process or taxation in any such jurisdiction where it is not so subject;

(5) cause all such Registrable Securities to be listed or quoted (as the case may be) on each national securities exchange or other securities market on which securities of the same class as the Registrable Securities are then listed or quoted;

(6) provide a transfer agent and registrar for all such Registrable Securities and a CUSIP number for all such Registrable Securities not later than the effective date of such Registration Statement;

(7) comply with all applicable rules and regulations of the Commission, and make available to its security holders an earnings statement satisfying the provisions of Section 11(a) of the Securities Act and Rule 158 thereunder (or any similar rule promulgated under the Securities Act) no later than 45 days after the end of any 12-month period (or 90 days after the end of any 12-month period if such period is a fiscal year) (or in each case within such extended period of time as may be permitted by the Commission for filing the applicable report with the Commission) (i) commencing at the end of any fiscal quarter in which Registrable Securities are sold to underwriters in an underwritten offering or (ii) if not sold to underwriters in such an offering, commencing on the first day of the first fiscal quarter of the Company after the effective date of a Registration Statement;

 

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(8) use its reasonable best efforts to prevent the issuance of any order suspending the effectiveness of a Registration Statement or suspending the qualification (or exemption from qualification) of any of the Registrable Securities included therein for sale in any jurisdiction, and, in the event of the issuance of any stop order suspending the effectiveness of a Registration Statement, or of any order suspending the qualification of any Registrable Securities included in such Registration Statement for sale in any jurisdiction, the Company will use its reasonable best efforts promptly to obtain the withdrawal of such order at the earliest possible moment;

(9) obtain “cold comfort” letters and updates thereof (which letters and updates (in form, scope and substance) shall be reasonably satisfactory to the managing underwriters, if any, and the Holders) from the independent certified public accountants of the Company (and, if necessary, any other independent certified public accountants of any subsidiary of the Company or of any business acquired by the Company for which financial statements and financial data are, or are required to be, included in the Registration Statement), addressed to each of the underwriters, if any, and each selling Holder of Registrable Securities, such letters to be in customary form and covering matters of the type customarily covered in “cold comfort” letters in connection with underwritten offerings and such other matters as the underwriters, if any, or the Holders of a majority of the Registrable Securities being included in the registration may reasonably request;

(10) obtain opinions of independent counsel to the Company and updates thereof (which counsel and opinions (in form, scope and substance) shall be reasonably satisfactory to the managing underwriters, if any, and the Holders of a majority of the Registrable Securities being included in the registration), addressed to each selling Holder and each of the underwriters, if any, covering the matters customarily covered in opinions of issuer’s counsel requested in underwritten offerings, such as the effectiveness of the Registration Statement and such other matters as may be requested by such counsel and underwriters, if any;

(11) promptly notify the selling Holders and the managing underwriters, if any, and confirm such notice in writing, when a Prospectus or any supplement or post-effective amendment to such Prospectus has been filed, and, with respect to a Registration Statement or any post-effective amendment thereto, when the same has become effective, (i) of any request by the Commission or any other federal or state governmental authority for amendments or supplements to a Registration Statement or related Prospectus or for additional information, (ii) of the issuance by the Commission of any stop order suspending the effectiveness of a Registration Statement or of any order preventing or suspending the use of any Prospectus or the initiation of any proceedings by any Person for that purpose, (iii) of the receipt by the Company of any notification with respect to the suspension of the qualification or exemption from qualification of a Registration Statement or any of the Registrable Securities for offer or sale under the securities or blue sky laws of any jurisdiction, or the contemplation, initiation or threatening, of any proceeding for such purpose, and (iv) of the happening of any event or the existence of any facts that make any statement made in such Registration Statement or Prospectus untrue in any material respect or that require the making of any changes in such

 

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Registration Statement or Prospectus so that it will not contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made (in the case of any Prospectus), not misleading (which notice shall be accompanied by an instruction to the selling Holders and the managing underwriters, if any, to suspend the use of the Prospectus until the requisite changes have been made);

(12) if requested by the managing underwriters, if any, or a Holder of Registrable Securities being sold, promptly incorporate in a prospectus, supplement or post-effective amendment such information as the managing underwriters, if any, and the Holders of a majority of the Registrable Securities being sold reasonably request to be included therein relating to the sale of the Registrable Securities, including, without limitation, information with respect to the number of shares of Registrable Securities being sold to underwriters, the purchase price being paid therefor by such underwriters and with respect to any other terms of the underwritten offering of the Registrable Securities to be sold in such offering, and make all required filings of such prospectus, supplement or post-effective amendment promptly following notification of the matters to be incorporated in such supplement or post-effective amendment;

(13) if requested, furnish to each selling Holder of Registrable Securities and the managing underwriter, without charge, at least one signed copy of the Registration Statement;

(14) as promptly as practicable upon the occurrence of any event contemplated by Section 4(b)(11)(iv) above, prepare a supplement or post-effective amendment to the Registration Statement or the Prospectus, or any document incorporated therein by reference, or file any other required document so that, as thereafter delivered to the purchasers of the Registrable Securities being sold hereunder, the Prospectus will not contain an untrue statement of a material fact or an omission to state a material fact required to be stated in a Registration Statement or Prospectus or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading; and

(15) if such offering is an underwritten offering, enter into such agreements (including an underwriting agreement in form, scope and substance as is customary in underwritten offerings) and take all such other appropriate and reasonable actions requested by the Holders owning a majority of the Registrable Securities being sold in connection therewith or by the managing underwriters (including cooperating in reasonable marketing efforts, including in connection with any Demand Registration, participation by senior executives of the Company in any “roadshow” or similar meeting with potential investors) in order to expedite or facilitate the disposition of such Registrable Securities, and in such connection, provide indemnification provisions and procedures substantially to the effect set forth in Section 6 hereof with respect to all parties to be indemnified pursuant to said Section. The above shall be done at each closing under such underwriting or similar agreement, or as and to the extent required thereunder.

Each Holder agrees by acquisition of such Registrable Securities that, upon receipt of written notice from the Company of the happening of any event of the kind described in Section 4(b)(11), such Holder will forthwith discontinue disposition of such Registrable Securities covered by such Registration Statement until such Holder’s receipt of the copies of the

 

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supplemented or amended Registration Statement contemplated by Section 4(b)(14), or until it is advised in writing by the Company that the use of the applicable Prospectus may be resumed, and has received copies of any additional or supplemental filings that are incorporated or deemed to be incorporated by reference in such prospectus (such period during which disposition is discontinued being an “Interruption Period”), and, if so directed by the Company, such Holder will deliver to the Company all copies of the Prospectus covering such Registrable Securities current at the time of receipt of such notice.

Section 5. Registration Expenses.

(a) Expenses Payable by the Company. The Company shall bear all expenses incurred with respect to the registration or attempted registration of the Registrable Securities pursuant to Sections 2 or 3 of this Agreement as provided herein. Such expenses shall include, without limitation, (i) all registration, qualification and filing fees (including, without limitation, (A) fees with respect to compliance with the rules and regulation of the Commission, (B) fees with respect to filings required to be made with the national securities exchange or national market system on which the Common Stock is then traded or quoted and (C) fees and expenses of compliance with state securities or blue sky laws (including, without limitation, fees and disbursements of counsel for the Company or the underwriters, or both, in connection with blue sky qualifications of Registrable Securities)), (ii) messenger and delivery expenses, word processing, duplicating and printing expenses (including without limitation, expenses of printing certificates for Registrable Securities in a form eligible for deposit with The Depository Trust Company, printing preliminary prospectuses, prospectuses, prospectus supplements, including those delivered to or for the account of the Holders and provided in this Agreement, and blue sky memoranda), (iii) fees and disbursements of counsel for the Company, (iv) fees and disbursements of all independent certificated public accountants for the Company (including, without limitation, the expense of any “comfort letters” required by or incident to such performance), (v) all out-of-pocket expenses of the Company (including without limitation, expenses incurred by the Company, its officers, directors, and employees performing legal or accounting duties or preparing or participating in “roadshow” presentations or of any public relations, investor relations or other consultants or advisors retained by the Company in connection with any roadshow, including travel and lodging expenses of such roadshows), (vi) fees and expenses incurred in connection with the quotation or listing of shares of Common Stock on any national securities exchange or other securities market, and (vii) reasonable fees and expenses of one firm of counsel for all selling Holders (which shall be chosen by the Holders of a majority of Registrable Securities to be included in such offering).

(b) Expenses Payable by the Holders. Each Holder shall pay all underwriting discounts and commissions or placement fees of underwriters or broker’s commissions incurred in connection with the sale or other disposition of Registrable Securities for or on behalf of such Holder’s account.

Section 6. Indemnification.

(a) Indemnification by the Company. The Company agrees to indemnify, to the fullest extent permitted by law, each Holder, each Affiliate of a Holder and each director, officer, employee, manager, stockholder, partner, member, counsel, agent or representative of

 

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such Holder and its Affiliates and each Person who controls any such Person (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) (collectively, “Holder Indemnified Parties”) against, and hold it and them harmless from, all losses, claims, damages, liabilities, actions, proceedings, costs (including, without limitation, costs of preparation and attorneys’ fees and disbursements) and expenses, including expenses of investigation and amounts paid in settlement (collectively, “Losses”) arising out of, caused by or based upon any untrue or alleged untrue statement of material fact contained in any Registration Statement, or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading (a “Misstatement/Omission”), or any violation or alleged violation by the Company of the Securities Act, the Exchange Act, any state securities law, or any rule or regulation promulgated under the Securities Act, the Exchange Act or any state securities law, except that the Company shall not be liable insofar as such Misstatement/Omission or violation is made in reliance upon and in conformity with information furnished in writing to the Company by such Holder expressly for use therein; provided, further, that the Company shall not be liable for a Holder’s failure to deliver or cause to be delivered (to the extent such delivery is required under the Securities Act) the Prospectus contained in the Registration Statement, furnished to it by the Company on a timely basis at or prior to the time such action is required by the Securities Act to the person claiming a Misstatement/Omission if such Misstatement/Omission was corrected in such Prospectus. In connection with an underwritten offering, the Company will indemnify such underwriters, selling brokers, dealer managers and similar securities industry professionals participating in the distribution, their officers and directors and each Person who controls such underwriters (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) to the same extent as provided above with respect to the indemnification of the Holders. This indemnity shall be in addition to any other indemnification arrangements to which the Company may otherwise be party.

(b) Indemnification by the Holders. In connection with any Registration Statement in which a Holder is participating, each such Holder agrees to indemnify, to the fullest extent permitted by law, the Company and each director and officer of the Company and each Person who controls the Company (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) against, and hold it harmless from, any Losses arising out of or based upon (i) any Misstatement/Omission contained in the Registration Statement, if and to the extent that such Misstatement/Omission was made in reliance upon and in conformity with information furnished in writing by such Holder for use therein, or (ii) the failure by such Holder to deliver or cause to be delivered (to the extent such delivery is required under the Securities Act) the Prospectus contained in the Registration Statement, furnished to it by the Company on a timely basis at or prior to the time such action is required by the Securities Act to the person claiming a Misstatement/Omission if such Misstatement/Omission was corrected in such Prospectus. Notwithstanding the foregoing, the obligation to indemnify will be individual (several and not joint) to each Holder and will be limited to the net amount of proceeds (net of payment of all expenses) received by such Holder from the sale of Registrable Securities pursuant to such Registration Statement giving rise to such indemnification obligation.

 

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(c) Conduct of Indemnification Proceedings. In case any action, claim or proceeding shall be brought against any Person entitled to indemnification hereunder, such indemnified party shall promptly notify each indemnifying party in writing, and such indemnifying party shall assume the defense thereof, including the employment of one counsel reasonably satisfactory to such indemnified party and payment of all fees and expenses incurred in connection with the defense thereof. The failure to so notify such indemnifying party shall relieve such indemnifying party of its indemnification obligations to such indemnified party to the extent that such failure to notify materially prejudiced such indemnifying party but not from any liability that it or they may have to the indemnified party for contribution or otherwise. Each indemnified party shall have the right to employ separate counsel in such action, claim or proceeding and participate in the defense thereof, but the fees and expenses of such counsel shall be at the expense of each indemnified party unless: (i) such indemnifying party has agreed to pay such expenses; (ii) such indemnifying party has failed promptly to assume the defense and employ counsel reasonably satisfactory to such indemnified party; or (iii) the named parties to any such action, claim or proceeding (including any impleaded parties) include both such indemnified party and such indemnifying party or an Affiliate or Controlling person of such indemnifying party, and such indemnified party shall have been advised in writing by counsel that either (x) there may be one or more legal defenses available to it which are different from or in addition to those available to such indemnifying party or such Affiliate or Controlling person or (y) a conflict of interest may exist if such counsel represents such indemnified party and such indemnifying party or its Affiliate or Controlling person; provided, however, that such indemnifying party shall not, in connection with any one such action or proceeding or separate but substantially similar or related actions or proceedings in the same jurisdiction arising out of the same general allegations or circumstances, be responsible hereunder for the fees and expenses of more than one separate firm of attorneys (in addition to any local counsel), which counsel shall be designated by such indemnified party or, in the event that such indemnified party is a Holder Indemnified Party, by the Holders of a majority of the Registrable Securities included in the subject Registration Statement.

No indemnifying party shall be liable for any settlement effected without its written consent (which consent may not be unreasonably delayed or withheld). Each indemnifying party agrees that it will not, without the indemnified party’s prior written consent, consent to entry of any judgment or settle or compromise any pending or threatened claim, action or proceeding in respect of which indemnification or contribution may be sought hereunder unless the foregoing contains an unconditional release, in form and substance reasonably satisfactory to the indemnified parties, of the indemnified parties from all liability and obligation arising therefrom. The indemnifying party’s liability to any such indemnified party hereunder shall not be extinguished solely because any other indemnified party is not entitled to indemnity hereunder.

(d) Survival. The indemnification provided for under this Agreement will (i) remain in full force and effect regardless of any investigation made by or on behalf of the indemnified party or any officer, director or controlling Person of such indemnified party, (ii) survive the transfer of securities and (iii) survive the termination of this Agreement.

(e) Right to Contribution. If the indemnification provided for in this Section 6 is unavailable to, or insufficient to hold harmless, an indemnified party under Section 6(a) or Section 6(b) above in respect of any Losses referred to in such Sections, then each applicable indemnifying party shall have an obligation to contribute to the amount paid or payable by such indemnified party as a result of such Losses in such proportion as is appropriate to reflect the relative fault of the Company, on the one hand, and of the Holder, on the other, in connection

 

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with the Misstatement/Omission or violation which resulted in such Losses, taking into account any other relevant equitable considerations. The amount paid or payable by a party as a result of the Losses referred to above shall be deemed to include, subject to the limitations set forth in Section 6(c) above, any legal or other fees or expenses reasonably incurred by such party in connection with any investigation, lawsuit or legal or administrative action or proceeding.

The relative fault of the Company, on the one hand, and of the Holder, on the other, shall be determined by reference to, among other things, whether the relevant Misstatement/Omission or violation relates to information supplied by the Company or by the Holder and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such Misstatement/Omission or violation.

The Company and each Holder agree that it would not be just and equitable if contribution pursuant to this Section 6(e) were determined by pro rata allocation or by any other method of allocation which does not take account of the equitable considerations referred to above. Notwithstanding the provisions of this Section 6(e), a Holder shall not be required to contribute any amount in excess of the amount by which (i) the amount (net of payment of all expenses) at which the securities that were sold by such Holder and distributed to the public were offered to the public exceeds (ii) the amount of any damages which such Holder has otherwise been required to pay by reason of such Misstatement/Omission or violation.

No Person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who was not guilty of such fraudulent misrepresentation.

Section 7. Rules 144 and 144A. The Company shall timely file the reports required to be filed by it under the Securities Act and the Exchange Act (including but not limited to the reports under Sections 13 and 15(d) of the Exchange Act referred to in subparagraph (c) of Rule 144 adopted by the Commission under the Securities Act) and the rules and regulations adopted by the Commission thereunder (or, if the Company is not required to file such reports, it will, upon the request of any Holder, make publicly available other information) and will take such further action as any Holder may reasonably request, all to the extent required from time to time to enable such Holder to sell Registrable Securities without registration under the Securities Act within the limitation of the exemptions provided by (a) Rule 144 and Rule 144A under the Securities Act, as such Rules may be amended from time to time, or (b) any similar rule or regulation hereafter adopted by the Commission.

Section 8. Underwritten Registrations.

(a) No Person may participate in any registration hereunder which is underwritten unless such Person (i) agrees to sell such Person’s securities on the basis provided in any underwriting arrangements approved by the Person or Persons entitled hereunder to approve such arrangements and (ii) completes and executes all questionnaires, powers of attorney, customary indemnities, underwriting agreements and other documents required under the terms of such underwriting arrangements; provided, that, no Holder included in any underwritten registration shall be required to make any representations or warranties to the Company or the underwriters other than representations and warranties regarding such Holder and such Holder’s intended method of distribution.

 

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(b) If any of the Registrable Securities covered by any Registration Statement are to be sold in an underwritten offering, the investment banker or investment bankers and manager or managers that will manage the offering will be selected by, and the underwriting arrangements with respect thereto will be approved by, the Company; provided, however, that such investment bankers and managers and underwriting arrangements must be reasonably satisfactory to the Holders of the majority of Registrable Securities to be included in such offering.

Section 9. Covenants of Holders. Each of the Holders hereby agrees (a) to cooperate with the Company and to furnish to the Company all such information regarding such Holder, its ownership of Registrable Securities and the disposition of such securities in connection with the preparation of the Registration Statement and any filings with any state securities commissions as the Company may reasonably request, (b) to the extent required by the Securities Act, to deliver or cause delivery of the Prospectus contained in the Registration Statement, any amendment or supplement thereto, to any purchaser of the Registrable Securities covered by the Registration Statement from the Holder and (c) if requested by the Company, to notify the Company of any sale of Registrable Securities by such Holder.

Section 10. Miscellaneous.

(a) No Inconsistent Agreements. The Company will not hereafter enter into any agreement with respect to its securities that is inconsistent with, adversely effects or violates the rights granted to the Holders in this Agreement; it being understood that the granting of additional demand or piggyback registration rights with respect to capital stock of the Company shall not be deemed adverse to the rights granted to Holders hereunder so long as they do not (x) reduce, except as set forth in this Agreement, the amount of Registrable Securities that any Holder may include in any registration contemplated in this Agreement or (y) restrict or otherwise limit the exercise by any Holder of its rights hereunder.

(b) Remedies. Any Person having rights under any provision of this Agreement will be entitled to enforce such rights specifically to recover damages caused by reason of any breach of any provision of this Agreement and to exercise all other rights granted by law. The parties hereto agree and acknowledge that money damages may not be an adequate remedy for any breach of the provisions of this Agreement and hereby agree to waive the defense in any action for specific performance or injunctive relief that a remedy at law would be adequate. Accordingly, any party may in its sole discretion apply to any court of law or equity of competent jurisdiction (without posting any bond or other security) for specific performance and for other injunctive relief in order to enforce or prevent violation of the provisions of this Agreement.

(c) Amendments and Waivers. This Agreement contains the entire understanding of the parties with respect to its subject matter and supersedes any and all prior agreements, and neither it nor any part of it may in any way be altered, amended, extended, waived, discharged or terminated except by a written agreement that specifically references this Agreement and the provisions to be so altered, amended, extended, waived, discharged or terminated is signed by each of the parties hereto and specifically states that it is intended to alter, amend, extend, waive, discharge or terminate this agreement or a provision hereof.

 

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(d) Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. The Holders may assign all rights under this Agreement; provided, however, that no Holder may transfer or assign its rights hereunder unless such transferring Holder shall, prior to any such transfer, obtain from the transferee a joinder agreement in a form reasonably satisfactory to the Company and deliver a copy of such joinder agreement to the Company and to the Holders. Only persons (other than the Stockholder hereto) that execute a joinder agreement shall be deemed to be Holders. The Company shall be given written notice by the transferring Holder at the time of the transfer stating the name and address of the transferee and identifying the Registrable Securities transferred, provided, that, failure to give such notice shall not affect the validity of such transfer or assignment.

(e) Severability. In the event that any one or more of the provisions contained herein, or the application thereof in any circumstances, is held invalid, illegal or unenforceable in any respect for any reason, the validity, legality and enforceability of any such provision in every other respect and of the remaining provisions hereof shall not be in any way impaired or affected, it being intended that the rights and privileges of the parties hereto shall be enforceable to the fullest extent permitted by law.

(f) Counterparts. This Agreement may be executed in any number of counterparts, any one of which need not contain the signatures of more than one party, but each of which when so executed shall be deemed to be an original and all such counterparts taken together shall constitute one and the same Agreement.

(g) Descriptive Headings: Interpretation. The descriptive headings of this Agreement are inserted for convenience of reference only and shall not limit or otherwise affect the meaning hereof. The use of the word “including” in this Agreement shall be by way of example rather than by limitation.

(h) Notices. All notices, requests and other communications provided for or permitted to be given under this Agreement must be in writing and shall be given by personal delivery, by certified or registered United States mail (postage prepaid, return receipt requested), by a nationally recognized overnight delivery service for next day delivery, or by facsimile transmission, as follows (or to such other address as any party may give in a notice given in accordance with the provisions hereof):

If to the Company:

Diamondback Energy, Inc.

14301 Caliber Drive, Suite 300

Oklahoma City, OK 73134

Attention: General Counsel

Facsimile: (405) 286-5920

 

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If to the Stockholder:

DB Energy Holdings LLC

c/o Wexford Capital LP

411 West Putnam Avenue

Greenwich, CT 06830

Attention: Arthur Amron

Facsimile: (203) 862-7312

All notices, requests or other communications will be effective and deemed given only as follows: (i) if given by personal delivery, upon such personal delivery, (ii) if sent by certified or registered mail, on the fifth business day after being deposited in the United States mail, (iii) if sent for next day delivery by overnight delivery service, on the date of delivery as confirmed by written confirmation of delivery, (iv) if sent by facsimile, upon the transmitter’s confirmation of receipt of such facsimile transmission, except that if such confirmation is received after 5:00 p.m. (in the recipient’s time zone) on a business day, or is received on a day that is not a business day, then such notice, request or communication will not be deemed effective or given until the next succeeding business day. Notices, requests and other communications sent in any other manner, including by electronic mail, will not be effective.

(i) GOVERNING LAW; SUBMISSION TO JURISDICTION. THIS AGREEMENT SHALL BE DEEMED TO BE MADE IN AND IN ALL RESPECTS SHALL BE INTERPRETED, CONSTRUED AND GOVERNED BY AND IN ACCORDANCE WITH THE LAW OF THE STATE OF DELAWARE WITHOUT REGARD TO THE CONFLICT OF LAW PRINCIPLES THEREOF. The parties hereby irrevocably submit to the jurisdiction of any federal court located in the State of Delaware or any Delaware state court solely in respect of the interpretation and enforcement of the provisions of this Agreement, and in respect of the transactions contemplated hereby, and hereby waive, and agree not to assert, as a defense in any action, suit or proceeding for the interpretation or enforcement hereof that it is not subject thereto or that such action, suit or proceeding may not be brought or is not maintainable in said courts or that the venue thereof may not be appropriate or that this Agreement or any such document may not be enforced in or by such courts, and the parties hereto irrevocably agree that all claims with respect to such action or proceeding shall be heard and determined in such a Delaware state or federal court. The parties hereby consent to and grant any such court jurisdiction over the person of such parties and over the subject matter of such dispute and agree that mailing of process or other papers in connection with any such action or proceeding in the manner provided in the Section on notices above or in such other manner as may be permitted by law shall be valid and sufficient service thereof.

EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH SUCH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. EACH PARTY CERTIFIES

 

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AND ACKNOWLEDGES THAT (I) NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, (II) EACH PARTY UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF THIS WAIVER, (III) EACH PARTY MAKES THIS WAIVER VOLUNTARILY, AND (IV) EACH PARTY HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

(j) Entire Agreement. This Agreement is intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein. This Agreement supersedes all prior agreements and understandings between the parties with respect to such subject matter.

[SIGNATURE PAGE FOLLOWS]

 

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IN WITNESS WHEREOF, the parties hereto have or have caused this Registration Rights Agreement to be duly executed as of the date first above written

 

 

Signature Page to Registration Rights Agreement

Exhibit 4.3

FORM OF

INVESTOR RIGHTS AGREEMENT

Dated as of             , 2012

by and between

DIAMONDBACK ENERGY, INC.

and

GULFPORT ENERGY CORPORATION

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TABLE OF CONTENTS

 

				Page
Section 1.		Definitions			1
Section 2.		Demand Registrations			4
Section 3.		Piggyback Registrations			7
Section 4.		Obligations of the Company			8
Section 5.		Registration Expenses			12
Section 6.		Indemnification			12
Section 7.		Rules 144 and 144A			15
Section 8.		Underwritten Registrations			15
Section 9.		Covenants of Holders			16
Section 10.		Board and Information Rights			16
Section 11.		Miscellaneous			20

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INVESTOR RIGHTS AGREEMENT

THIS INVESTOR RIGHTS AGREEMENT (the “Agreement”) is made and entered into as of             , 2012, by and between Diamondback Energy, Inc., a Delaware corporation (the “Company”), and Gulfport Energy Corporation, a Delaware corporation (the “Stockholder” or “Gulfport”).

WHEREAS, the Company was formed in December 2011 in contemplation of an initial public offering of common stock of the Company (“Common Stock Offering”).

WHEREAS, the Stockholder will be issued shares (the “Shares”) of Common Stock (as defined below), all of which were validly issued, fully paid and non-assessable, pursuant to the Contribution Agreement (as defined below).

WHEREAS, the parties hereto desire to enter into this Agreement to govern certain of their rights, duties and obligations relating to registration of the Registrable Securities (as defined below), the nomination of directors, board advisor rights and information rights.

NOW, THEREFORE, for good, valuable and binding consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, now agree as follows:

STATEMENT OF AGREEMENT

Section 1. Definitions. As used in this Agreement, the following terms shall have the meanings set forth below:

“Agreement” has the meaning set forth in the introductory paragraph of this Agreement.

“Affiliate” means, with respect to any Person, a Person that, directly or indirectly, through one or more intermediaries, Controls, is Controlled by, or is under common Control with the specified Person.

“Board” means the Board of Directors of the Company.

“Board Advisor” has the meaning set forth in Section 10(c)(1) of this Agreement.

“Charter” means the Amended and Restated Certificate of Incorporation of the Company, as amended from time to time.

“Commission” means the United States Securities and Exchange Commission or any other United States federal agency at the time administering the Securities Act.

“Common Stock” means the Company’s common stock, par value $0.01 per share, or any other shares of capital stock or other securities of the Company into which such shares of Common Stock shall be reclassified or changed, including by reason of a merger, consolidation, reorganization or recapitalization. If the Common Stock has been so reclassified or changed, or if the Company pays a dividend or makes a distribution on the Common Stock in shares of

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capital stock, or subdivides (or combines) its outstanding shares of Common Stock into a greater (or smaller) number of shares of Common Stock, a share of Common Stock shall be deemed to be such number of shares of stock and amount of other securities to which a holder of a share of Common Stock outstanding immediately prior to such change, reclassification, exchange, dividend, distribution, subdivision or combination would be entitled.

“Common Stock Offering” has the meaning set forth in the recitals of this Agreement.

“Company” has the meaning set forth in the introductory paragraph of this Agreement.

“Contribution Agreement” means that certain Contribution Agreement by and between the Company and the Stockholder dated as of May 7, 2012.

“Controlling,” “Controlled by” and “under common Control with” refer to the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ownership of voting securities, any equity interest, or a membership interest in a non-stock corporation; by contract; by power granted in bylaws or similar governing documents; or otherwise. Without limiting the foregoing, any ownership interest greater than fifty percent (50%) for purposes hereof constitutes “Control.”

“DB Holdings Registration Rights Agreement” means that certain Registration Rights Agreement by and between the Company and DB Energy Holdings LLC dated as of the date hereof.

“Delay Period” has the meaning set forth in Section 4(a) of this Agreement.

“Demand Notice” has the meaning set forth in Section 2(a) of this Agreement.

“Demand Registration” has the meaning set forth in Section 2(a) of this Agreement.

“Director” means a member of the Board.

“Equity Right” means any options, warrants, exchangeable or convertible securities, subscription rights, exchange rights, statutory pre-emptive rights, preemptive rights granted under its Charter, stock appreciation rights, phantom stock, profit participation or similar rights, or any other right or instrument pursuant to which any person may be entitled to purchase any security interest in the Company.

“Exchange Act” means the United States Securities Exchange Act of 1934, as amended, and the rules and regulations of the Commission thereunder.

“Gulfport” has the meaning set forth in the introductory paragraph hereto.

“Gulfport Director” has the meaning set forth in Section 10(a) of this Agreement.

“Holder(s)” means a person who owns Registrable Securities and is either (i) a Stockholder or a Permitted Transferee of a Stockholder that has agreed to be bound by the terms of this Agreement as if such Person were a Stockholder, (ii) upon the death of any Holder, the executor of the estate of such Holder or such Holder’s heirs, devisees, legatees or assigns or (iii) upon the disability of any Holder, any guardian or conservator of such Holder.

 

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“Holder Indemnified Parties” has the meaning set forth in Section 6(a) of this Agreement.

“Independent Director” means a natural person who is “independent” under the applicable rules and regulations of the SEC and the rules and regulations of The NASDAQ Global Market or the then applicable exchange on which the Common Stock is then traded (“Marketplace Rules”).

“Independent Directors” has the meaning set forth in Section 10(a) of this Agreement.

“Interruption Period” has the meaning set forth in the last paragraph in Section 4(b) of this Agreement.

“Large Accelerated Filer” has the meaning ascribed to it in Rule 12b-2 promulgated under the Exchange Act.

“Law” means any law (statutory, common or otherwise), constitution, ordinance, rule, regulation, executive order or other similar authority enacted, adopted, promulgated or applied by any legislature, agency, bureau, branch, department, division, commission, court, tribunal or other similar recognized organization or body of any federal, state, county, municipal, local or foreign government or other similar recognized organization or body exercising similar powers or authority.

“Losses” has the meaning set forth in Section 6(a) of this Agreement.

“Misstatement/Omission” has the meaning set forth in Section 6(a) of this Agreement.

“Permitted Transferee” means any Person to whom the rights under this Agreement have been assigned in accordance with the provisions of Section 11(d) of this Agreement.

“Person” means any natural person, corporation, partnership, firm, association, trust, government, governmental agency, limited liability company or any other entity, whether acting in an individual, fiduciary or other capacity.

“Piggyback Registration” has the meaning set forth in Section 3(a) of this Agreement.

“Prospectus” means the prospectus included in any Registration Statement, as amended or supplemented by any prospectus supplement, with respect to the terms of the offering of any portion of the Registrable Securities covered by such Registration Statement, and all other amendments and supplements to the Prospectus, including post-effective amendments, and all material incorporated by reference or deemed to be incorporated by reference in such prospectus.

 

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“Registrable Securities” means (i) the Shares, (ii) any other shares of Common Stock that may be acquired by a Holder prior to or after the closing of the Common Stock Offering and (iii) any shares of Common Stock issuable pursuant to any rights to acquire Common Stock held by a Holder prior to or after the closing of the Common Stock Offering. If as a result of any reclassification, stock dividends or stock splits or in connection with a combination of shares, recapitalization, merger, consolidation or other reorganization or other transaction or event, any capital stock, evidence of indebtedness, warrants, options, rights or other securities (collectively “Other Securities”) are issued or transferred to a Holder in respect of Registrable Securities held by the Holder, references herein to Registrable Securities shall be deemed to include such Other Securities. As to any particular Registrable Securities, such securities will cease to be Registrable Securities when (i) they have been distributed to the public pursuant to an offering registered under the Securities Act, or may legally be distributed to the public in one transaction pursuant to Rule 144 under the Securities Act, (ii) they have been distributed to the public pursuant to Rule 144 (or any successor provision) under the Securities Act, or (iii) they have been sold to any Person to whom the rights under this Agreement are not assigned in accordance with this Agreement.

“Registration Statement” means any registration statement under the Securities Act of the Company that covers any of the Registrable Securities, including the related Prospectus, amendments and supplements to such registration statement or Prospectus, including pre- and post-effective amendments, all exhibits, and all materials incorporated by reference or deemed to be incorporated by reference in such registration statement or Prospectus.

“Securities Act” means the United States Securities Act of 1933, as amended, and the rules and regulations of the Commission promulgated thereunder.

“Shares” has the meaning set forth in the recitals of this Agreement.

“Stockholder” has the meaning set forth in the introductory paragraph of this Agreement.

Section 2. Demand Registrations.

(a) Right to Demand. Upon the terms and subject to the conditions of this Agreement, Holders of at least a majority of the aggregate amount of outstanding Registrable Securities shall have the right, by written notice (the “Demand Notice”) given to the Company, to request the Company to register under and in accordance with the provisions of the Securities Act all or part of the Registrable Securities designated by such Holders (a “Demand Registration”). Upon receipt of any such Demand Notice, the Company will promptly notify all other Holders of the receipt of such Demand Notice and allow them the opportunity to include Registrable Securities in the proposed registration by giving notice to the Company within five days after the Holder receives such notice; provided, however, that Holders joining in a proposed registration pursuant to this sentence shall not be deemed to have exercised a Demand Registration for purposes of Section 2(b) hereof and such Holders shall be included in such registration on the basis set forth in Section 2(h) hereof. The Company shall not be required to register any Registrable Securities under this Section 2 unless the anticipated aggregate offering price to the public for any such offering of the Registrable Securities included in such Demand Notice is expected to be at least $1 million.

 

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(b) Number of Demand Registrations. Upon the terms and subject to the conditions of this Agreement, Holders shall be entitled to have three Demand Registrations effected. A Demand Registration shall not be deemed to be effected and shall not count as a Demand Registration of any Person (i) if a Registration Statement with respect thereto shall not have become effective under the Securities Act and remained effective (A) for at least 180 days (excluding any Interruption Period or Delay Period) in the case of a Demand Registration that is not on a Form S-3 or other comparable form or (B) for at least two years (excluding any Interruption Period or Delay Period) in the case of a Demand Registration on Form S-3 or other comparable form, or until the completion of the distribution of the Registrable Securities thereunder, whichever is earlier (including, without limitation, because of withdrawal of such Registration Statement by the Holders pursuant to Section 2(f) hereunder), (ii) if, after it has become effective, such registration is interfered with for any reason by any stop order, injunction or other order or requirement of the Commission or any governmental authority, or as a result of the initiation of any proceeding for such stop order by the Commission through no fault of the Holders and the result of such interference is to prevent the Holders from disposing of such Registrable Securities proposed to be sold in accordance with the intended methods of disposition, or (iii) if the conditions to closing specified in the purchase agreement or underwriting agreement entered into in connection with any underwritten offering shall not be satisfied or waived with the consent of the Holders of a majority in number of the Registrable Securities to be included in such Demand Registration, other than as a result of any breach by the Holders or any underwriter of its obligations thereunder or hereunder.

(c) Registration Statement. Subject to paragraph (a) above, as soon as practicable, but in any event within 45 days of the date on which the Company first receives one or more Demand Notices pursuant to Section 2(a) hereof, the Company shall file with the Commission a Registration Statement on the appropriate form for the registration and sale of the total number of Registrable Securities specified in such Demand Notice, together with the number of Registrable Securities requested to be included in the Demand Registration by other Holders, in accordance with the intended method or methods of distribution specified by the Holders in such Demand Notice. The Company shall use its reasonable best efforts to cause such Registration Statement to be declared effective by the Commission as soon as reasonably practicable.

(d) Amendments; Supplements. Subject to Section 4(a), upon the occurrence of any event that would cause the Registration Statement (A) to contain a material misstatement or omission or (B) to be not effective and usable for resale of Registrable Securities during the period that such Registration Statement is required to be effective and usable, the Company shall file an amendment to the Registration Statement as soon as reasonably practicable if the Registration Statement is not on Form S-3 or another comparable form and such misstatement or omission is not corrected as soon as reasonably practicable by incorporation by reference, in the case of clause (A), correcting any such misstatement or omission and, in the case of either clause (A) or (B), use its reasonable best efforts to cause such amendment to be declared effective and such Registration Statement to become usable as soon as reasonably practicable thereafter.

(e) Effectiveness. The Company agrees to use its reasonable best efforts to keep any Registration Statement filed pursuant to this Section 2 continuously effective and usable for the sale of Registrable Securities until the earlier of (i) (a) in the case of a Demand Registration for delayed or continuous offerings of Registrable Securities filed on Form S-3 or another comparable form, two years after the date on which the Commission declares such

 

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Registration Statement effective (excluding any Interruption Period or Delay Period) or (b) in the case of a Demand Registration that is not on Form S-3 or another comparable form, 180 days from the date on which the Commission declares such Registration Statement effective (excluding any Interruption Period or Delay Period) and (ii) the date on which there are no longer any Registrable Securities.

(f) Holders Withdrawal. Holders of a majority in number of the Registrable Securities to be included in a Demand Registration pursuant to this Section 2 may, at any time prior to the effective date of the Registration Statement in respect thereof, revoke such request by providing a written notice to the Company to such effect.

(g) Preemption of Demand Registration. Notwithstanding anything to the contrary contained herein, after receiving a written request for a Demand Registration, the Company may elect to effect an underwritten primary registration in lieu of the Demand Registration if the Company’s Board of Directors believes that such primary registration would be in the best interests of the Company. If the Company so elects to effect a primary registration, the Company shall give prompt written notice (which shall be given not later than 20 days after the date of the Demand Notice) to all Holders of its intention to effect such a registration and shall afford the Holders the rights contained in Section 3 with respect to Piggyback Registrations. In the event that the Company so elects to effect a primary registration after receiving a request for a Demand Registration, the Company shall use its reasonable best efforts to have the Registration Statement declared effective by the Commission as soon as reasonably practicable. In addition, the request for a Demand Registration shall be deemed to have been withdrawn and such primary registration shall not be deemed to be a Demand Registration.

(h) Priority on Demand Registrations. If a Demand Registration is an underwritten offering and includes securities for sale by the Company, and the managing underwriter (such underwriter to be chosen by Holders of a majority of the Registrable Securities included in such registration, subject to the Company’s reasonable approval) advises the Company, in writing, that, in its good faith judgment, the number of securities requested to be included in such registration exceeds the number which can be sold in such offering without materially and adversely affecting the marketability of the offering, then the Company will include in any such registration the maximum number of shares that the managing underwriter advises the Company can be sold in such offering allocated as follows: (i) first, the Registrable Securities requested to be included in such registration by the initiating Holders and securities of other Holders of Registrable Securities and holders of Registrable Securities (as defined in the DB Holdings Registration Rights Agreement), with all such securities to be included on a pro rata basis (or in such other proportion mutually agreed among such Holders) based on the amount of securities requested to be included therein and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriter as aforesaid, the securities that the Company proposes to sell together with such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed upon among the Company and such other holders) based on the amount of securities requested to be included therein. If the initiating Holders are not allowed to register all of the Registrable Securities requested to be included by such Holders because of allocations required by this section, such initiating Holders shall not be deemed to have exercised a Demand Registration for purposes of Section 2(b).

 

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Section 3. Piggyback Registrations.

(a) Right to Piggyback Registrations. Whenever the Company or another party having registration rights proposes that the Company register any of the Company’s equity securities under the Securities Act (other than a registration on Form S-4 relating solely to a transaction described in Rule 145 of the Securities Act or a registration on Form S-8 or any successor forms thereto), whether or not for sale for the Company’s own account, the Company will give prompt written notice of such proposed filing to all Holders at least 15 days before the anticipated filing date. Such notice shall offer such Holders the opportunity to register such amount of Registrable Securities as they shall request (a “Piggyback Registration”). Subject to Section 3(b) hereof, the Company shall include in each such Piggyback Registration all Registrable Securities with respect to which the Company has received written requests for inclusion therein within 10 days after such notice has been given by the Company to the Holders. If the Registration Statement relating to the Piggyback Registration is for an underwritten offering, such Registrable Securities shall be included in the underwriting on the same terms and conditions as the securities otherwise being sold through the underwriters. Each Holder shall be permitted to withdraw all or part of the Registrable Securities from a Piggyback Registration at any time prior to the effective time of such Piggyback Registration.

(b) Priority on Piggyback Registrations. If a Piggyback Registration is an underwritten offering by or through one or more underwriters of recognized standing and the managing underwriters advise the party or parties initiating such offering in writing (a copy of which writing shall be provided to the Holders) that in their good faith judgment the number of securities requested to be included in such registration exceeds the number which can be sold in such offering without materially and adversely affecting the marketability of the offering, then any such registration shall include the maximum number of shares that such managing underwriters advise can be sold in such offering allocated as follows: (x) if the Company has initiated such offering, (i) first, the securities the Company proposes to sell, and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriters as aforesaid, (A) the Registrable Securities to be included in such registration by the Holders and the holders of Registrable Securities (as defined in the DB Registration Rights Agreement), with all such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed among the Holders and such other holders), based on the amount of Registrable Securities and other securities requested to be included therein, and then, if additional securities may be included (B) to such additional securities on a pro rata basis (or in such other proportion mutually agreed among them), (y) if a holder of Registrable Securities (as defined in the DB Holdings Registration Rights Agreement) has initiated such offering, (i) first, the securities the holders under the DB Registration Rights Agreement propose to sell together with the securities the Holders of Registrable Securities hereunder propose to sell on a pro rata basis (or in such other proportion mutually agreed upon among such holders and the Holders), based on the amount of securities requested to be included therein and (ii) second, to the extent that any other securities may be included without exceeding the limitations recommended by the underwriters as aforesaid, all such other securities on a pro rata basis (or in such other proportion mutually agreed upon among such other holders) based on the amount of securities requested to be included therein, and (z) if a party other than the Company or a holder under the DB Holdings Registration Rights Agreement initiated such offering, securities proposed to be sold by the Company, and the Registrable Securities to be included in such registration by the Holders, with such additional securities to be included on a pro rata basis (or in such other proportion mutually agreed among the Company, the Holders and such other holders), based on the amount of Registrable Securities and other securities requested to be included therein.

 

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Section 4. Obligations of the Company.

(a) Delay Period. Notwithstanding the foregoing, the Company shall have the right to delay the filing of any Registration Statement otherwise required to be prepared and filed by the Company pursuant to Sections 2 or 3, or to suspend the use of any Registration Statement, for a period not in excess of 60 consecutive calendar days (a “Delay Period”) if (i) the Board of Directors of the Company by written resolution determines that filing or maintaining the effectiveness of such Registration Statement would have a material adverse effect on the Company or the holders of its capital stock in relation to any material acquisition or disposition, financing or other corporate transaction or (ii) the Board of Directors of the Company by written resolution determines in good faith that the filing of a Registration Statement or maintaining the effectiveness of a current Registration Statement would require disclosure of material information that the Company has a valid business purpose for retaining as confidential at such time. The Company shall not be entitled to exercise a Delay Period more than one time in any 12-month period.

(b) Registration Procedures. Whenever the Company is required to register Registrable Securities pursuant to Sections 2 or 3 hereof, the Company will use its reasonable best efforts to effect the registration to permit the sale of such Registrable Securities in accordance with the intended method or methods of disposition thereof, and pursuant thereto the Company will as expeditiously as possible:

(1) prepare and file with the Commission a Registration Statement with respect to such Registrable Securities as prescribed by Sections 2 or 3 on a form available for the sale of the Registrable Securities by the holders thereof in accordance with the intended method or methods of distribution thereof and use its reasonable best efforts to cause each such Registration Statement to become and remain effective within the time periods and otherwise as provided herein;

(2) prepare and file with the Commission such amendments (including post-effective amendments) to the Registration Statement and such supplements to the Prospectus as may be necessary to keep such Registration Statement effective within the time periods and otherwise as provided herein and to comply with the provisions of the Securities Act with respect to the disposition of all securities covered by such Registration Statement until such time as all of such securities have been disposed of in accordance with the intended methods of disposition by the seller or sellers thereof set forth in such Registration Statement, except as otherwise expressly provided herein;

(3) furnish to each selling Holder of Registrable Securities covered by a Registration Statement and to each underwriter, if any, such number of copies of such Registration Statement, each amendment and post-effective amendment thereto, the Prospectus included in such Registration Statement (including each preliminary prospectus and any

 

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supplement to such Prospectus and any other prospectus filed under Rule 424 of the Securities Act), in each case including all exhibits, and such other documents as such Holder may reasonably request in order to facilitate the disposition of the Registrable Securities owned by such Holder or to be disposed of by such underwriter (the Company hereby consenting to the use in accordance with all applicable Law of each such Registration Statement (or amendment or post-effective amendment thereto) and each such Prospectus (or preliminary prospectus or supplement thereto) by each such Holder and the underwriters, if any, in connection with the offering and sale of the Registrable Securities covered by such Registration Statement or Prospectus);

(4) use its reasonable best efforts to register or qualify and, if applicable, to cooperate with the selling Holders, the underwriters, if any, and their respective counsel in connection with the registration or qualification (or exemption from such registration or qualification) of, the Registrable Securities for offer and sale under the securities or blue sky laws of such jurisdictions as any selling Holder or managing underwriters (if any) shall reasonably request, to keep each such registration or qualification (or exemption therefrom) effective during the period such Registration Statement is required to be kept effective as provided herein and to do any and all other acts or things necessary or advisable to enable the disposition in such jurisdictions of the securities covered by the applicable Registration Statement; provided, however, that the Company will not be required to (i) qualify generally to do business in any jurisdiction where it would not otherwise be required to qualify but for this paragraph or (ii) consent to general service of process or taxation in any such jurisdiction where it is not so subject;

(5) cause all such Registrable Securities to be listed or quoted (as the case may be) on each national securities exchange or other securities market on which securities of the same class as the Registrable Securities are then listed or quoted;

(6) provide a transfer agent and registrar for all such Registrable Securities and a CUSIP number for all such Registrable Securities not later than the effective date of such Registration Statement;

(7) comply with all applicable rules and regulations of the Commission, and make available to its security holders an earnings statement satisfying the provisions of Section 11(a) of the Securities Act and Rule 158 thereunder (or any similar rule promulgated under the Securities Act) no later than 45 days after the end of any 12-month period (or 90 days after the end of any 12-month period if such period is a fiscal year) (or in each case within such extended period of time as may be permitted by the Commission for filing the applicable report with the Commission) (i) commencing at the end of any fiscal quarter in which Registrable Securities are sold to underwriters in an underwritten offering or (ii) if not sold to underwriters in such an offering, commencing on the first day of the first fiscal quarter of the Company after the effective date of a Registration Statement;

(8) use its reasonable best efforts to prevent the issuance of any order suspending the effectiveness of a Registration Statement or suspending the qualification (or exemption from qualification) of any of the Registrable Securities included therein for sale in any jurisdiction, and, in the event of the issuance of any stop order suspending the effectiveness

 

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of a Registration Statement, or of any order suspending the qualification of any Registrable Securities included in such Registration Statement for sale in any jurisdiction, the Company will use its reasonable best efforts promptly to obtain the withdrawal of such order at the earliest possible moment;

(9) obtain “cold comfort” letters and updates thereof (which letters and updates (in form, scope and substance) shall be reasonably satisfactory to the managing underwriters, if any, and the Holders) from the independent certified public accountants of the Company (and, if necessary, any other independent certified public accountants of any subsidiary of the Company or of any business acquired by the Company for which financial statements and financial data are, or are required to be, included in the Registration Statement), addressed to each of the underwriters, if any, and each selling Holder of Registrable Securities, such letters to be in customary form and covering matters of the type customarily covered in “cold comfort” letters in connection with underwritten offerings and such other matters as the underwriters, if any, or the Holders of a majority of the Registrable Securities being included in the registration may reasonably request;

(10) obtain opinions of independent counsel to the Company and updates thereof (which counsel and opinions (in form, scope and substance) shall be reasonably satisfactory to the managing underwriters, if any, and the Holders of a majority of the Registrable Securities being included in the registration), addressed to each selling Holder and each of the underwriters, if any, covering the matters customarily covered in opinions of issuer’s counsel requested in underwritten offerings, such as the effectiveness of the Registration Statement and such other matters as may be requested by such counsel and underwriters, if any;

(11) promptly notify the selling Holders and the managing underwriters, if any, and confirm such notice in writing, when a Prospectus or any supplement or post-effective amendment to such Prospectus has been filed, and, with respect to a Registration Statement or any post-effective amendment thereto, when the same has become effective, (i) of any request by the Commission or any other federal or state governmental authority for amendments or supplements to a Registration Statement or related Prospectus or for additional information, (ii) of the issuance by the Commission of any stop order suspending the effectiveness of a Registration Statement or of any order preventing or suspending the use of any Prospectus or the initiation of any proceedings by any Person for that purpose, (iii) of the receipt by the Company of any notification with respect to the suspension of the qualification or exemption from qualification of a Registration Statement or any of the Registrable Securities for offer or sale under the securities or blue sky laws of any jurisdiction, or the contemplation, initiation or threatening, of any proceeding for such purpose, and (iv) of the happening of any event or the existence of any facts that make any statement made in such Registration Statement or Prospectus untrue in any material respect or that require the making of any changes in such Registration Statement or Prospectus so that it will not contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made (in the case of any Prospectus), not misleading (which notice shall be accompanied by an instruction to the selling Holders and the managing underwriters, if any, to suspend the use of the Prospectus until the requisite changes have been made);

 

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(12) if requested by the managing underwriters, if any, or a Holder of Registrable Securities being sold, promptly incorporate in a prospectus, supplement or post-effective amendment such information as the managing underwriters, if any, and the Holders of a majority of the Registrable Securities being sold reasonably request to be included therein relating to the sale of the Registrable Securities, including, without limitation, information with respect to the number of shares of Registrable Securities being sold to underwriters, the purchase price being paid therefor by such underwriters and with respect to any other terms of the underwritten offering of the Registrable Securities to be sold in such offering, and make all required filings of such prospectus, supplement or post-effective amendment promptly following notification of the matters to be incorporated in such supplement or post-effective amendment;

(13) if requested, furnish to each selling Holder of Registrable Securities and the managing underwriter, without charge, at least one signed copy of the Registration Statement;

(14) as promptly as practicable upon the occurrence of any event contemplated by Section 4(b)(11)(iv) above, prepare a supplement or post-effective amendment to the Registration Statement or the Prospectus, or any document incorporated therein by reference, or file any other required document so that, as thereafter delivered to the purchasers of the Registrable Securities being sold hereunder, the Prospectus will not contain an untrue statement of a material fact or an omission to state a material fact required to be stated in a Registration Statement or Prospectus or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading; and

(15) if such offering is an underwritten offering, enter into such agreements (including an underwriting agreement in form, scope and substance as is customary in underwritten offerings) and take all such other appropriate and reasonable actions requested by the Holders owning a majority of the Registrable Securities being sold in connection therewith or by the managing underwriters (including cooperating in reasonable marketing efforts, including in connection with any Demand Registration, participation by senior executives of the Company in any “roadshow” or similar meeting with potential investors) in order to expedite or facilitate the disposition of such Registrable Securities, and in such connection, provide indemnification provisions and procedures substantially to the effect set forth in Section 6 hereof with respect to all parties to be indemnified pursuant to said Section. The above shall be done at each closing under such underwriting or similar agreement, or as and to the extent required thereunder.

Each Holder agrees by acquisition of such Registrable Securities that, upon receipt of written notice from the Company of the happening of any event of the kind described in Section 4(b)(11), such Holder will forthwith discontinue disposition of such Registrable Securities covered by such Registration Statement until such Holder’s receipt of the copies of the supplemented or amended Registration Statement contemplated by Section 4(b)(14), or until it is advised in writing by the Company that the use of the applicable Prospectus may be resumed, and has received copies of any additional or supplemental filings that are incorporated or deemed to be incorporated by reference in such prospectus (such period during which disposition is discontinued being an “Interruption Period”), and, if so directed by the Company, such Holder will deliver to the Company all copies of the Prospectus covering such Registrable Securities current at the time of receipt of such notice.

 

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Section 5. Registration Expenses.

(a) Expenses Payable by the Company. The Company shall bear all expenses incurred with respect to the registration or attempted registration of the Registrable Securities pursuant to Sections 2 or 3 of this Agreement as provided herein. Such expenses shall include, without limitation, (i) all registration, qualification and filing fees (including, without limitation, (A) fees with respect to compliance with the rules and regulation of the Commission, (B) fees with respect to filings required to be made with the national securities exchange or national market system on which the Common Stock is then traded or quoted and (C) fees and expenses of compliance with state securities or blue sky laws (including, without limitation, fees and disbursements of counsel for the Company or the underwriters, or both, in connection with blue sky qualifications of Registrable Securities)), (ii) messenger and delivery expenses, word processing, duplicating and printing expenses (including without limitation, expenses of printing certificates for Registrable Securities in a form eligible for deposit with The Depository Trust Company, printing preliminary prospectuses, prospectuses, prospectus supplements, including those delivered to or for the account of the Holders and provided in this Agreement, and blue sky memoranda), (iii) fees and disbursements of counsel for the Company, (iv) fees and disbursements of all independent certificated public accountants for the Company (including, without limitation, the expense of any “comfort letters” required by or incident to such performance), (v) all out-of-pocket expenses of the Company (including without limitation, expenses incurred by the Company, its officers, directors, and employees performing legal or accounting duties or preparing or participating in “roadshow” presentations or of any public relations, investor relations or other consultants or advisors retained by the Company in connection with any roadshow, including travel and lodging expenses of such roadshows), (vi) fees and expenses incurred in connection with the quotation or listing of shares of Common Stock on any national securities exchange or other securities market, and (vii) reasonable fees and expenses of one firm of counsel for all selling Holders (which shall be chosen by the Holders of a majority of Registrable Securities to be included in such offering).

(b) Expenses Payable by the Holders. Each Holder shall pay all underwriting discounts and commissions or placement fees of underwriters or broker’s commissions incurred in connection with the sale or other disposition of Registrable Securities for or on behalf of such Holder’s account.

Section 6. Indemnification.

(a) Indemnification by the Company. The Company agrees to indemnify, to the fullest extent permitted by law, each Holder, each Affiliate of a Holder and each director, officer, employee, manager, stockholder, partner, member, counsel, agent or representative of such Holder and its Affiliates and each Person who controls any such Person (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) (collectively, “Holder Indemnified Parties”) against, and hold it and them harmless from, all losses, claims, damages, liabilities, actions, proceedings, costs (including, without limitation, costs of preparation and attorneys’ fees and disbursements) and expenses, including expenses of investigation and amounts paid in settlement (collectively, “Losses”) arising out of, caused by or based upon any untrue or alleged untrue statement of material fact contained in any Registration Statement, or any omission or alleged omission of a material fact required to be stated therein or

 

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necessary to make the statements therein not misleading (a “Misstatement/Omission”), or any violation or alleged violation by the Company of the Securities Act, the Exchange Act, any state securities law, or any rule or regulation promulgated under the Securities Act, the Exchange Act or any state securities law, except that the Company shall not be liable insofar as such Misstatement/Omission or violation is made in reliance upon and in conformity with information furnished in writing to the Company by such Holder expressly for use therein; provided, further, that the Company shall not be liable for a Holder’s failure to deliver or cause to be delivered (to the extent such delivery is required under the Securities Act) the Prospectus contained in the Registration Statement, furnished to it by the Company on a timely basis at or prior to the time such action is required by the Securities Act to the person claiming a Misstatement/Omission if such Misstatement/Omission was corrected in such Prospectus. In connection with an underwritten offering, the Company will indemnify such underwriters, selling brokers, dealer managers and similar securities industry professionals participating in the distribution, their officers and directors and each Person who controls such underwriters (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) to the same extent as provided above with respect to the indemnification of the Holders. This indemnity shall be in addition to any other indemnification arrangements to which the Company may otherwise be party.

(b) Indemnification by the Holders. In connection with any Registration Statement in which a Holder is participating, each such Holder agrees to indemnify, to the fullest extent permitted by law, the Company and each director and officer of the Company and each Person who controls the Company (within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act) against, and hold it harmless from, any Losses arising out of or based upon (i) any Misstatement/Omission contained in the Registration Statement, if and to the extent that such Misstatement/Omission was made in reliance upon and in conformity with information furnished in writing by such Holder for use therein, or (ii) the failure by such Holder to deliver or cause to be delivered (to the extent such delivery is required under the Securities Act) the Prospectus contained in the Registration Statement, furnished to it by the Company on a timely basis at or prior to the time such action is required by the Securities Act to the person claiming a Misstatement/Omission if such Misstatement/Omission was corrected in such Prospectus. Notwithstanding the foregoing, the obligation to indemnify will be individual (several and not joint) to each Holder and will be limited to the net amount of proceeds (net of payment of all expenses) received by such Holder from the sale of Registrable Securities pursuant to such Registration Statement giving rise to such indemnification obligation.

(c) Conduct of Indemnification Proceedings. In case any action, claim or proceeding shall be brought against any Person entitled to indemnification hereunder, such indemnified party shall promptly notify each indemnifying party in writing, and such indemnifying party shall assume the defense thereof, including the employment of one counsel reasonably satisfactory to such indemnified party and payment of all fees and expenses incurred in connection with the defense thereof. The failure to so notify such indemnifying party shall relieve such indemnifying party of its indemnification obligations to such indemnified party to the extent that such failure to notify materially prejudiced such indemnifying party but not from any liability that it or they may have to the indemnified party for contribution or otherwise. Each indemnified party shall have the right to employ separate counsel in such action, claim or proceeding and participate in the defense thereof, but the fees and expenses of such counsel shall

 

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be at the expense of each indemnified party unless: (i) such indemnifying party has agreed to pay such expenses; (ii) such indemnifying party has failed promptly to assume the defense and employ counsel reasonably satisfactory to such indemnified party; or (iii) the named parties to any such action, claim or proceeding (including any impleaded parties) include both such indemnified party and such indemnifying party or an Affiliate or controlling person of such indemnifying party, and such indemnified party shall have been advised in writing by counsel that either (x) there may be one or more legal defenses available to it which are different from or in addition to those available to such indemnifying party or such Affiliate or controlling person or (y) a conflict of interest may exist if such counsel represents such indemnified party and such indemnifying party or its Affiliate or controlling person; provided, however, that such indemnifying party shall not, in connection with any one such action or proceeding or separate but substantially similar or related actions or proceedings in the same jurisdiction arising out of the same general allegations or circumstances, be responsible hereunder for the fees and expenses of more than one separate firm of attorneys (in addition to any local counsel), which counsel shall be designated by such indemnified party or, in the event that such indemnified party is a Holder Indemnified Party, by the Holders of a majority of the Registrable Securities included in the subject Registration Statement.

No indemnifying party shall be liable for any settlement effected without its written consent (which consent may not be unreasonably delayed or withheld). Each indemnifying party agrees that it will not, without the indemnified party’s prior written consent, consent to entry of any judgment or settle or compromise any pending or threatened claim, action or proceeding in respect of which indemnification or contribution may be sought hereunder unless the foregoing contains an unconditional release, in form and substance reasonably satisfactory to the indemnified parties, of the indemnified parties from all liability and obligation arising therefrom. The indemnifying party’s liability to any such indemnified party hereunder shall not be extinguished solely because any other indemnified party is not entitled to indemnity hereunder.

(d) Survival. The indemnification provided for under this Agreement will (i) remain in full force and effect regardless of any investigation made by or on behalf of the indemnified party or any officer, director or controlling Person of such indemnified party, (ii) survive the transfer of securities and (iii) survive the termination of this Agreement.

(e) Right to Contribution. If the indemnification provided for in this Section 6 is unavailable to, or insufficient to hold harmless, an indemnified party under Section 6(a) or Section 6(b) above in respect of any Losses referred to in such Sections, then each applicable indemnifying party shall have an obligation to contribute to the amount paid or payable by such indemnified party as a result of such Losses in such proportion as is appropriate to reflect the relative fault of the Company, on the one hand, and of the Holder, on the other, in connection with the Misstatement/Omission or violation which resulted in such Losses, taking into account any other relevant equitable considerations. The amount paid or payable by a party as a result of the Losses referred to above shall be deemed to include, subject to the limitations set forth in Section 6(c) above, any legal or other fees or expenses reasonably incurred by such party in connection with any investigation, lawsuit or legal or administrative action or proceeding.

The relative fault of the Company, on the one hand, and of the Holder, on the other, shall be determined by reference to, among other things, whether the relevant Misstatement/Omission or violation relates to information supplied by the Company or by the Holder and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such Misstatement/Omission or violation.

 

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The Company and each Holder agree that it would not be just and equitable if contribution pursuant to this Section 6(e) were determined by pro rata allocation or by any other method of allocation which does not take account of the equitable considerations referred to above. Notwithstanding the provisions of this Section 6(e), a Holder shall not be required to contribute any amount in excess of the amount by which (i) the amount (net of payment of all expenses) at which the securities that were sold by such Holder and distributed to the public were offered to the public exceeds (ii) the amount of any damages which such Holder has otherwise been required to pay by reason of such Misstatement/Omission or violation.

No Person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who was not guilty of such fraudulent misrepresentation.

Section 7. Rules 144 and 144A. The Company shall timely file the reports required to be filed by it under the Securities Act and the Exchange Act (including but not limited to the reports under Sections 13 and 15(d) of the Exchange Act referred to in subparagraph (c) of Rule 144 adopted by the Commission under the Securities Act) and the rules and regulations adopted by the Commission thereunder (or, if the Company is not required to file such reports, it will, upon the request of any Holder, make publicly available other information) and will take such further action as any Holder may reasonably request, all to the extent required from time to time to enable such Holder to sell Registrable Securities without registration under the Securities Act within the limitation of the exemptions provided by (a) Rule 144 and Rule 144A under the Securities Act, as such Rules may be amended from time to time, or (b) any similar rule or regulation hereafter adopted by the Commission.

Section 8. Underwritten Registrations.

(a) No Person may participate in any registration hereunder which is underwritten unless such Person (i) agrees to sell such Person’s securities on the basis provided in any underwriting arrangements approved by the Person or Persons entitled hereunder to approve such arrangements and (ii) completes and executes all questionnaires, powers of attorney, customary indemnities, underwriting agreements and other documents required under the terms of such underwriting arrangements; provided, that, no Holder included in any underwritten registration shall be required to make any representations or warranties to the Company or the underwriters other than representations and warranties regarding such Holder and such Holder’s intended method of distribution.

(b) If any of the Registrable Securities covered by any Registration Statement are to be sold in an underwritten offering, the investment banker or investment bankers and manager or managers that will manage the offering will be selected by, and the underwriting arrangements with respect thereto will be approved by, the Company; provided, however, that such investment bankers and managers and underwriting arrangements must be reasonably satisfactory to the Holders of the majority of Registrable Securities to be included in such offering.

 

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Section 9. Covenants of Holders. Each of the Holders hereby agrees (a) to cooperate with the Company and to furnish to the Company all such information regarding such Holder, its ownership of Registrable Securities and the disposition of such securities in connection with the preparation of the Registration Statement and any filings with any state securities commissions as the Company may reasonably request, (b) to the extent required by the Securities Act, to deliver or cause delivery of the Prospectus contained in the Registration Statement, any amendment or supplement thereto, to any purchaser of the Registrable Securities covered by the Registration Statement from the Holder and (c) if requested by the Company, to notify the Company of any sale of Registrable Securities by such Holder.

Section 10. Board and Information Rights

(a) Board Composition. The parties agree that so long as Gulfport beneficially owns (as defined in Rule 13d-3 promulgated under the Exchange Act (“Rule 13d-3”)) more than 10% of the then issued and outstanding Common Stock, (i) the business and affairs of the Company shall be managed through a Board consisting of up to seven Directors, of which three Directors shall be Independent Directors and (ii) Gulfport shall have the right to designate one Director (“Gulfport Director”). For purposes of this Agreement, in determining the percentage of shares of Common Stock beneficially owned by Gulfport, only shares of Common Stock then issued and outstanding shall be included in the denominator and any Equity Right that has not then been exercised, converted or exchanged shall be excluded from the denominator regardless of the application of the beneficial ownership rules of Rule 13d-3.

(b) Company Action to Nominate and Elect the Gulfport Director. Subject to Section 10(g), the Company shall cause the initial Gulfport Director designated in accordance with Section 10(a) to be appointed to the Board prior to the completion of the Common Stock Offering and thereafter to use its commercially reasonable efforts to cause the Gulfport Director to be nominated for election to the Board at each annual meeting of the Company’s stockholders at which directors are to be elected (or by stockholder consents in lieu of a meeting, if applicable), shall solicit proxies (or stockholder consents in lieu of a meeting, if applicable) in favor thereof, and at each annual meeting of the Company’s stockholders at which Directors are to be elected, shall recommend that the Company’s stockholders elect to the Board each such individual nominated for election at such annual meeting of the Company’s stockholders (or stockholder consents in lieu of a meeting, if applicable). So long as Gulfport has the right to designate a Gulfport Director under this Agreement, if for any reason the Gulfport Director is not elected to the Board by the Company’s stockholders, Gulfport will be entitled to the Board Advisor rights set forth in Section 10(c).

(c) Board Advisor Rights.

(1) So long as Gulfport has the right to designate a Gulfport Director under this Agreement and there is no Gulfport Director in office, Gulfport shall have the right to appoint one individual as an advisor to the Board (a “Board Advisor”). The Board Advisor shall be entitled to attend meetings of the Board and any meetings of any committee of the Board and

 

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to receive all information provided to the members of the Board and any committee thereof (including minutes of previous meetings of the Board and any committee thereof). The Board Advisor shall advise and counsel the Board on the business and operations of the Company as requested by the Board. The Board Advisor is not, and shall not have the duties and responsibilities of, a Director of the Company, and the terms “director” or “member of the Board” as used in this Agreement shall not be deemed to mean or include the Board Advisor. Without limiting the generality of the foregoing, the Board Advisor shall not be entitled to vote on any matter presented for action by the Board. The Board Advisor may be given such designations (including without limitation “advisory director”) as the Board may from time to time determine. For the avoidance of doubt, no Board Advisor shall have fiduciary obligations to the Company or the Company’s stockholders, but shall be subject to all applicable securities Laws and to the confidentiality obligations applicable to Gulfport under Section 10(k)(2).

(2) Gulfport shall have the right, in its sole discretion, to appoint the Board Advisor and to remove the Board Advisor, as well as the right, in its sole discretion, to fill vacancies created by reason of the death, removal or resignation thereof. Gulfport shall have the right at any time to remove (with or without cause) the Board Advisor. In the event there is a vacancy in the Board Advisor position at any time and for any reason (whether as a result of death, disability, retirement, resignation or removal of the Board Advisor), Gulfport shall have the right to designate a different individual to replace such Board Advisor.

(d) Gulfport Designation, Removal and Vacancies. In the event a vacancy is created on the Board of the Gulfport Director at any time that Gulfport has the right to designate a Gulfport Director under this Agreement (whether as a result of death, disability, retirement, resignation, removal or otherwise), Gulfport shall have the right, in its sole discretion, to designate a different individual to replace such Gulfport Director and the Company shall nominate such Gulfport Director for election to the Board as provided in Section 10(b).

(e) Committees. For so long as Gulfport has the right to designate a Gulfport Director, any committee composed of Directors shall consist of at least one Gulfport Director provided that such Gulfport Director is “independent” and otherwise satisfies all requirements under the applicable rules and regulations of the SEC and the Marketplace Rules to serve on such committee.

(f) Election Not to Exercise Designation Rights. Notwithstanding anything in Section 10 to the contrary, this Section 10 confers upon Gulfport the right, but not the obligation, to designate the Gulfport Director, and Gulfport may, at its option, elect not to exercise any such right to designate the Gulfport Director.

(g) Qualifications and Information. Notwithstanding anything to the contrary contained in this Agreement, each nominee for election to the Board designated by Gulfport shall, in the reasonable judgment of the Board, (A) have the requisite skill and experience to serve as a director of a publicly traded company, and (B) not be prohibited or disqualified from serving as a director of the Company pursuant to the applicable rules and regulations of the SEC and the Marketplace Rules or by applicable Law. The Board may adopt additional standards of skill and experience desired of potential candidates for nomination to the Board of Directors, which will be reflected in a charter of a committee of the Board or other similar document.

 

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Gulfport shall timely provide the Company with accurate and complete information relating to its designee that may be required to be disclosed by the Company under the Exchange Act. In addition, at the Company’s request, Gulfport shall cause its designee to complete and execute the Company’s standard Director and Officer Questionnaire prior to being admitted to the Board or any committee thereof or standing for reelection at an annual meeting of the Company’s stockholders or at such other time as may be requested by the Company.

(h) Director Insurance and Indemnification. The Company will obtain and maintain directors’ liability insurance and will at all times exercise the powers granted to it by its Organizational Documents, and by applicable Law to indemnify and hold harmless to the fullest extent permitted by applicable Law present or former directors and officers of the Company against any threatened or actual claim, action, suit, proceeding or investigation made against them arising from their service in such capacities (or service in such capacities for another enterprise at the request of the Company).

(i) Expenses of Directors. The Company will promptly reimburse the Gulfport Director or Board Advisor, to the extent not an employee of the Company, for all of his or her reasonable out-of-pocket expenses incurred in attending each meeting of the Board or any committee thereof consistent with the Company’s policies.

(j) Information Rights. In addition to, and without limiting any rights that Gulfport may have with respect to inspection of the books and records of the Company under applicable Laws, the Company shall furnish to Gulfport, the following information, so long as Gulfport owns shares of Common Stock:

(1) Annual Reports. As soon as available, and in any event within 50 days after the end of each Fiscal Year, the audited balance sheet of the Company as at the end of each such Fiscal Year and the audited statements of income, cash flows and changes in stockholders’ equity for such year, accompanied by the certification of independent certified public accountants of recognized national standing selected by the Board, to the effect that, except as set forth therein, such financial statements have been prepared in accordance with GAAP, applied on a basis consistent with prior years and fairly present in all material respects the financial condition of the Company as of the dates thereof and the results of its operations and changes in its cash flows and stockholders’ equity for the periods covered thereby.

(2) Quarterly Reports. As soon as available, and in any event within 30 days after the end of each fiscal quarter, the balance sheet of the Company at the end of such quarter and the statements of income, cash flows and changes in stockholders’ equity for such quarter, all in reasonable detail and all prepared in accordance with GAAP, consistently applied, and certified by the Chief Financial Officer of the Company.

(3) Information Required as a Result of Stockholder’s Filing Status. The Company acknowledges that Stockholder is a Large Accelerated Filer and agrees to cooperate, provide sufficient access and provide all information necessary for Stockholder to satisfy its financial reporting and Exchange Act reporting obligations as a Large Accelerated Filer. In accordance therewith, upon a request in writing by Stockholder that it requires certain financial information related to the Company in connection with Stockholder’s filing obligations

 

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under the Exchange Act, including, but not limited a request for the information included in or described in the annual or quarterly reports set forth in Sections 10(j)(1) and 10(j)(2) as well as supporting information and schedules, the Company shall respond with such requested information in a timely manner, but in any event no less than five (5) business days from receipt of the written request with the information requested. If for any reason the Company does not have the requested information available to it, it will respond to the Stockholder in writing within two (2) business days from receipt of the written request specifying the reasons for unavailability of the information and a date upon which it believes the information will be available. When such requested information becomes available, the Company shall promptly send it to the Stockholder. In addition, in the event that Stockholder’s financial reporting and Exchange Act reporting obligations require it to audit or perform other accounting or review procedures with respect to the Company’s financials or any information included therein, the Company shall, and shall cause its officers, Directors and employees to afford Stockholder and its representatives, during normal business hours and upon reasonable notice, access at all reasonable times to its officers, employees, auditors, properties, offices, plants and other facilities and to all books and records, necessary to perform any such audit or other accounting or review procedures. Such access and information shall be provided within the time period reasonably necessary to allow Stockholder to conduct and complete its audit in a timely fashion and to timely include compliant financials in its Exchange Act reports and to timely file its Exchange Act reports.

(k) Inspection Rights.

(1) The Company shall, and shall cause its officers, Directors and employees to afford Gulfport. for so long as Gulfport has the right to designate a Gulfport Director or has Board Advisor rights pursuant to Section 10(c), the opportunity to consult with its officers from time to time regarding the Company’s affairs, finances and accounts as Gulfport may reasonably request upon reasonable notice. The right set forth in this Section 10(k) shall not, and is not intended to, limit any rights which Gulfport may have with respect to the books and records of the Company, or to inspect its properties or discuss its affairs, finances and accounts under the laws of the jurisdiction in which the Company is incorporated.

(2) Gulfport agrees that it will keep confidential and will not disclose, divulge or use for any purpose, other than to monitor its investment in the Company, any confidential information obtained from the Company pursuant to the terms of this Agreement, unless such confidential information (A) is known or becomes known to the public in general (other than as a result of a breach of this Section 10(k)(2) by Gulfport), (B) is or has been independently developed or conceived by the Gulfport without use of the Company’s confidential information or (C) is or has been made known or disclosed to Gulfport by a third party without a breach of any obligation of confidentiality such third party may have to the Company; provided, however, that Gulfport may disclose confidential information (a) to its attorneys, accountants, consultants, and other professionals to the extent needed for their services in connection with monitoring its investment in the Company, (b) to any officer, director or employees of Gulfport in the ordinary course of business, or (c) as may otherwise be required by law, provided that Gulfport takes reasonable steps to minimize the extent of any such required disclosure and subject, in the case of clauses (a) and (b) to each recipient’s obligation to maintain the confidentiality of that information as if such recipient was a party hereto.

 

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(3) The Company acknowledges that Gulfport is in the oil and gas business and therefore is always reviewing information of many oil and gas companies and properties which compete directly or indirectly with those of the Company. Subject to its agreement to only use confidential information to monitor its investment in the Company, nothing in this Agreement shall preclude or in any way restrict Gulfport from investing or participating in any particular enterprise whether or not such enterprise has products or services which compete with those of the Company.

Section 11. Miscellaneous.

(a) No Inconsistent Agreements. The Company will not hereafter enter into any agreement with respect to its securities that is inconsistent with, adversely effects or violates the rights granted to the Holders in this Agreement; it being understood that the granting of additional demand or piggyback registration rights with respect to capital stock of the Company shall not be deemed adverse to the rights granted to Holders hereunder so long as they do not (x) reduce, except as set forth in this Agreement, the amount of Registrable Securities that any Holder may include in any registration contemplated in this Agreement or (y) restrict or otherwise limit the exercise by any Holder of its rights hereunder.

(b) Remedies. Any Person having rights under any provision of this Agreement will be entitled to enforce such rights specifically to recover damages caused by reason of any breach of any provision of this Agreement and to exercise all other rights granted by law. The parties hereto agree and acknowledge that money damages may not be an adequate remedy for any breach of the provisions of this Agreement and hereby agree to waive the defense in any action for specific performance or injunctive relief that a remedy at law would be adequate. Accordingly, any party may in its sole discretion apply to any court of law or equity of competent jurisdiction (without posting any bond or other security) for specific performance and for other injunctive relief in order to enforce or prevent violation of the provisions of this Agreement.

(c) Amendments and Waivers. This Agreement contains the entire understanding of the parties with respect to its subject matter and supersedes any and all prior agreements, and neither it nor any part of it may in any way be altered, amended, extended, waived, discharged or terminated except by a written agreement that specifically references this Agreement and the provisions to be so altered, amended, extended, waived, discharged or terminated is signed by each of the parties hereto and specifically states that it is intended to alter, amend, extend, waive, discharge or terminate this agreement or a provision hereof.

(d) Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Except for the Board and information rights contained in Section 10 (which rights are non-transferable), the Holders may assign all rights under this Agreement; provided, however, that no Holder may transfer or assign its rights hereunder unless such transferring Holder shall, prior to any such transfer, obtain from the transferee a joinder agreement in a form reasonably satisfactory to the Company and deliver a copy of such joinder agreement to the Company and to the Holders. Only persons (other than the Stockholder hereto) that execute a joinder agreement shall be deemed to be Holders. The Company shall be given written notice by the transferring Holder at the time of the transfer stating the name and address of the transferee and identifying the Registrable Securities transferred, provided, that, failure to give such notice shall not affect the validity of such transfer or assignment.

 

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(e) Severability. In the event that any one or more of the provisions contained herein, or the application thereof in any circumstances, is held invalid, illegal or unenforceable in any respect for any reason, the validity, legality and enforceability of any such provision in every other respect and of the remaining provisions hereof shall not be in any way impaired or affected, it being intended that the rights and privileges of the parties hereto shall be enforceable to the fullest extent permitted by law.

(f) Counterparts. This Agreement may be executed in any number of counterparts, any one of which need not contain the signatures of more than one party, but each of which when so executed shall be deemed to be an original and all such counterparts taken together shall constitute one and the same Agreement.

(g) Descriptive Headings: Interpretation. The descriptive headings of this Agreement are inserted for convenience of reference only and shall not limit or otherwise affect the meaning hereof. The use of the word “including” in this Agreement shall be by way of example rather than by limitation.

(h) Notices. All notices, requests and other communications provided for or permitted to be given under this Agreement must be in writing and shall be given by personal delivery, by certified or registered United States mail (postage prepaid, return receipt requested), by a nationally recognized overnight delivery service for next day delivery, or by facsimile transmission, as follows (or to such other address as any party may give in a notice given in accordance with the provisions hereof):

If to the Company:

Diamondback Energy, Inc.

14301 Caliber Drive, Suite 300

Oklahoma City, OK 73134

Attention: General Counsel

Facsimile: (405) 463-6982

If to the Stockholder:

Gulfport Energy Corporation

4313 N. May Avenue, Suite 100

Oklahoma City, OK 73134

Attention: Chief Financial Officer

Facsimile: (405) 848-8816

All notices, requests or other communications will be effective and deemed given only as follows: (i) if given by personal delivery, upon such personal delivery, (ii) if sent by certified or registered mail, on the fifth business day after being deposited in the United States mail, (iii) if

 

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sent for next day delivery by overnight delivery service, on the date of delivery as confirmed by written confirmation of delivery, (iv) if sent by facsimile, upon the transmitter’s confirmation of receipt of such facsimile transmission, except that if such confirmation is received after 5:00 p.m. (in the recipient’s time zone) on a business day, or is received on a day that is not a business day, then such notice, request or communication will not be deemed effective or given until the next succeeding business day. Notices, requests and other communications sent in any other manner, including by electronic mail, will not be effective.

(i) GOVERNING LAW; SUBMISSION TO JURISDICTION. THIS AGREEMENT SHALL BE DEEMED TO BE MADE IN AND IN ALL RESPECTS SHALL BE INTERPRETED, CONSTRUED AND GOVERNED BY AND IN ACCORDANCE WITH THE LAW OF THE STATE OF DELAWARE WITHOUT REGARD TO THE CONFLICT OF LAW PRINCIPLES THEREOF. The parties hereby irrevocably submit to the jurisdiction of any federal court located in the State of Delaware or any Delaware state court solely in respect of the interpretation and enforcement of the provisions of this Agreement, and in respect of the transactions contemplated hereby, and hereby waive, and agree not to assert, as a defense in any action, suit or proceeding for the interpretation or enforcement hereof that it is not subject thereto or that such action, suit or proceeding may not be brought or is not maintainable in said courts or that the venue thereof may not be appropriate or that this Agreement or any such document may not be enforced in or by such courts, and the parties hereto irrevocably agree that all claims with respect to such action or proceeding shall be heard and determined in such a Delaware state or federal court. The parties hereby consent to and grant any such court jurisdiction over the person of such parties and over the subject matter of such dispute and agree that mailing of process or other papers in connection with any such action or proceeding in the manner provided in the Section on notices above or in such other manner as may be permitted by law shall be valid and sufficient service thereof.

EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE EACH SUCH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. EACH PARTY CERTIFIES AND ACKNOWLEDGES THAT (I) NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, (II) EACH PARTY UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF THIS WAIVER, (III) EACH PARTY MAKES THIS WAIVER VOLUNTARILY, AND (IV) EACH PARTY HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

 

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(j) Entire Agreement. This Agreement is intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein. This Agreement supersedes all prior agreements and understandings between the parties with respect to such subject matter.

[SIGNATURE PAGE FOLLOWS]

 

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IN WITNESS WHEREOF, the parties hereto have or have caused this Investor Rights Agreement to be duly executed as of the date first above written

 

 

Signature Page to Investor Rights Agreement

Exhibit 10.6

SHARED SERVICES AGREEMENT

by and between

WINDSOR ENERGY RESOURCES LLC

AND

WINDSOR PERMIAN LLC

Dated as of

March 1, 2008

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SHARED SERVICES AGREEMENT

THIS SHARED SERVICES AGREEMENT (the “Agreement”) is entered into effective as of the 1st day of March, 2008, by and between WINDSOR ENERGY RESOURCES LLC, a Delaware limited liability company, its subsidiaries, affiliates, successors and assigns (“Windsor”), and WINDSOR PERMIAN LLC, a Delaware limited liability company (“Permian”). Windsor and Permian may be referred to in this Agreement separately as a “Party” or collectively as the “Parties”.

WITNESSETH:

WHEREAS, Permian desires to receive certain administrative and support services from Windsor, subject to the terms and conditions described in this Agreement; and

WHEREAS, in order to assist Permian in general operations, Windsor desires to provide such services to Permian, subject to the terms and conditions described in this Agreement.

NOW, THEREFORE, in consideration of the covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound hereby, agree as follows:

ARTICLE I

SERVICES

SECTION 1.1 SERVICES. Subject to the terms and conditions of this Agreement, Windsor, acting directly or through its Affiliates (as hereafter defined) or their respective employees, agents, contractors or independent third parties, agrees to provide or cause to be provided to Permian, its affiliates and its subsidiaries the services set forth on Exhibit “A” (with any additional services provided pursuant to Section 1.3 being collectively referred to as the “Services”). Permian acknowledges and agrees that, except as may be expressly set forth in this Agreement as to a Service, Windsor shall not be obligated to provide, or cause to be provided, any service or goods to Permian. For purposes of this Agreement, “Affiliate” shall mean as to any person another person that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with, such person, and “control” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of the person controlled, whether through ownership of voting securities, by contract or otherwise. Notwithstanding anything in this Agreement to the contrary, neither a Party or any of its majority owned subsidiaries shall be deemed an Affiliate of the other Party.

SECTION 1.2 SERVICE COORDINATORS. Each Party will nominate a representative to act as its primary contact with respect to the provision of the Services as contemplated by this Agreement (collectively, the “Service Coordinators”). The initial Service Coordinators shall be Robert Fitzgerald for Windsor and Tracy Dick for Permian. Unless otherwise agreed, all notices and communications relating to this Agreement other than those day to day communications and billings relating to the actual provision of the Services shall be directed to the Service Coordinators.

 

Shared Services Agreement – Windsor to Permian – Page 1

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SECTION 1.3 ADDITIONAL SERVICES. Subject to any limitations set forth in this Agreement and Exhibit “A”, Permian may request additional Services from Windsor by providing written notice. Upon the mutual written agreement as to the nature, cost, duration and scope of such additional Services, the Parties shall supplement in writing Exhibit “A” to include such additional Services. In accordance with Section 3.2, the Parties may discontinue one or more Services under this Agreement.

SECTION 1.4 EMPLOYEES, STANDARD OF PERFORMANCE AND LEGAL COMPLIANCE.

(a) Windsor shall cause its employees (collectively, the “Employees”) to devote such time and effort to the business of Permian as shall be reasonably necessary to perform the Services; provided, that the Employees shall not be precluded from engaging in other business activities for or on behalf of Windsor or its Affiliates. The Employees shall not receive any additional compensation from Permian for holding any office, serving as an officer of Permian or providing the Services without the prior written consent of Windsor. All duties and services of the Employees shall be rendered at the offices of Windsor subject to reasonable travel requirements. Unless otherwise expressly provided for in this Agreement, all matters pertaining to the employment of the Employees are the sole responsibility of Windsor, which shall in all respects be the employer of such Employees. At no time shall the employees, agents and consultants of Windsor, any independent contractors engaged by Windsor and/or the employees of any such independent contractors be considered employees of Permian. This Agreement is not one of agency between Windsor and Permian, but one with Windsor engaged independently in the business of providing services as an independent contractor. All employment arrangements are therefore solely Windsor’s concern, and Permian shall not have any liability with respect thereto except as otherwise expressly set forth in this Agreement.

(b) The Services shall be performed with the same general degree of care as when performed within the Windsor’s organization. In the event Windsor fails to provide, or cause to be provided, the Services, the sole and exclusive remedy of Permian shall be to, at Permian’s sole discretion, either (i) have the Service performed until satisfactory, or (ii) not pay for such Service, or if payment has already been made, receive a refund of the payment made for such defective service; provided that in the event Windsor defaults in the manner described in Section 3.3, Permian shall have the further rights set forth in Section 3.3.

(c) Windsor further covenants and represents to Permian that it shall comply in all material respect with all applicable laws, rules, regulations and requirements of any governmental body which may be applicable to the Services provided by Windsor. Windsor shall obtain and maintain all material permits, approvals and licenses necessary or appropriate to perform its duties and obligations (including all Services) under this Agreement and shall at all times comply with the terms and conditions of such permits, approvals and licenses. Windsor shall notify Permian’s Service Coordinator immediately upon receipt of notice of (i) any material threatened or pending governmental orders, proceedings or lawsuit involving Permian or (ii) any material violations relating to the use or maintenance of Permian’s assets.

 

Shared Services Agreement – Windsor to Permian – Page 2

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SECTION 1.5 CONFLICT WITH LAWS. Notwithstanding any other provision of this Agreement, Windsor shall not be required to provide a Service to the extent the provision thereof would violate or contravene any applicable law, To the extent that the provision of any such Service would violate any applicable law, the Parties agree to work together in good faith to provide such Service in a manner which would not violate any law.

ARTICLE II

SERVICE CHARGES

SECTION 2.1 COMPENSATION. As compensation for the Services and any expenses reasonably incurred by Windsor in providing the Services during the term of this Agreement, Permian shall pay Windsor as provided in Exhibit “A” or at such hourly rates or other amounts that are otherwise mutually agreed to in writing between the Parties.

SECTION 2.2 PAYMENT. Any amounts due to Windsor from Permian for the Services shall be due and payable within thirty (30) days after the calendar month in which the Services were provided.

ARTICLE III

TERM AND DISCONTINUATION OF SERVICES

SECTION 3.1 TERM. The term of this Agreement shall be effective as of the date first written above and shall continue in force until the earlier of (i) two (2) years from the date of this Agreement or (ii) the termination of all Services in accordance with Section 3.3. Upon the expiration of the term, this Agreement shall continue on a month-to-month basis until canceled by either Party upon thirty (30) days prior written notice. Any extension of this Agreement must be made by the Parties in writing.

SECTION 3.2 DISCONTINUANCE OF SERVICES. Either Party may, with the other Party’s prior written consent (which consent shall not be unreasonably withheld, conditioned or delayed), elect to discontinue any individual Service from time to time. In the event of any termination with respect to one or more, but less than all, of the Services, this Agreement shall continue in full force and effect with respect to any remaining Services. The Parties shall supplement Exhibit “A” to reflect the termination of any such Services.

SECTION 3.3 TERMINATION. This Agreement may be terminated as follows: (i) Either Party may terminate this Agreement at any time upon not less than sixty (60) days written notice to the other Party; or (ii) either Party may terminate this Agreement upon immediate written notice if the other Party is in material breach or default with respect to any term or provision of this Agreement and fails to cure the same within thirty (30) days of receipt of notice of such breach or default. Permian’s right to terminate this Agreement as provided in this Section 3.3 and the rights set forth in Sections 1.4(b) and 4.1 shall constitute Permian’s sole and exclusive rights and remedies for a breach by Windsor under this Agreement including, but not limited to, any breach caused by an Affiliate of Windsor or other third party providing a Service. Upon the termination of this Agreement by Permian, Windsor shall be entitled to immediate payment of any unpaid balance of any amounts due or to be due to Windsor through the date of termination.

 

Shared Services Agreement – Windsor to Permian – Page 3

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ARTICLE IV

INDEMNIFICATION

SECTION 4.1 BY WINDSOR. Windsor, its Affiliates and their respective shareholders, members, partners, directors, managers, officers, employees and agents shall have no liability for any damages, losses, deficiencies, obligations, penalties, judgments, settlements, claims, payments, fines, interest costs and expenses, including the costs and expenses of any and all actions and demands, assessments, judgments, settlements and compromises relating thereto and the costs and expenses of attorneys, accountants, consultants and other professionals fees and expenses incurred in the investigation or defense thereof or the enforcement of rights hereunder, (collectively, the “Losses”) to Permian, its Affiliates or their respective shareholders, members, partners, directors, managers, officers, employees or agents with respect to any Services, except for Losses arising out of or resulting from the gross negligence or willful misconduct of Windsor. Windsor will indemnify, defend and hold harmless Permian, its Affiliates and their respective shareholders, members, partners, directors, managers, officers, employees and agents from and against any Losses arising out of or resulting from such gross negligence or willful misconduct.

SECTION 4.2 BY PERMIAN. Permian shall indemnify, defend and hold harmless Windsor, its Affiliates and their respective shareholders, members, partners, directors, managers, officers, employees and agents from and against any Losses arising out of or resulting from Windsor providing the Services, except for Losses arising out of or resulting from the gross negligence or willful misconduct of Windsor, its Affiliates or their respective shareholders, members, partners, directors, managers, officers, employees or agents.

ARTICLE V

CONFIDENTIALITY

SECTION 5.1 CONFIDENTIALITY. The Parties shall hold and shall cause their respective shareholders, members, partners, directors, managers, officers, employees, agents, consultants and advisors to hold, in strict confidence and not to disclose or release without the prior written consent of the other Party, any and all Confidential Information (as hereafter defined); provided, that the Parties may disclose, or may permit disclosure of, Confidential Information (i) to their respective auditors, attorneys, financial advisors, bankers and other appropriate consultants and advisors who have a need to know such information and are informed of their obligation to hold such information confidential to the same extent as is applicable to the Parties and in respect of whose failure to comply with such obligations, Windsor or Permian, as the case may be, will be responsible, or (ii) to the extent any member of a Party is compelled to disclose any such Confidential Information by judicial or administrative process or, in the opinion of legal counsel, by other requirements of law.

SECTION 5.2 PROTECTIVE ORDER. Notwithstanding the foregoing, in the event that any demand or request for disclosure of Confidential Information is made pursuant to Section 5.l(ii) above, either Party, as the case may be, shall promptly notify the other Party of the

 

Shared Services Agreement – Windsor to Permian – Page 4

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existence of such request or demand and shall provide the other Party with a reasonable opportunity to seek an appropriate protective order or other remedy, which both Parties will cooperate in seeking to obtain. In the event that such appropriate protective order or other remedy is not obtained, the Party whose Confidential Information is required to be disclosed shall or shall cause the other Party to furnish, or cause to be furnished, only that portion of the Confidential Information that is legally required to be disclosed.

SECTION 5.3 CONFIDENTIAL INFORMATION DEFINED. For purposes of this Agreement, “Confidential Information” shall mean any and all proprietary, technical or operational information, data or material of a Party of a non-public or confidential nature, whether marked as such or not, which has been disclosed by a Party to the other Party in written, oral (including by recording), electronic, or visual form to, or otherwise has come into the possession of, the other Party, (except to the extent that such Confidential Information can be shown to have been (a) in the public domain through no fault of a Party or (b) later lawfully is acquired by the Receiving Party from another source that does not have any confidentiality obligations to the other Party).

SECTION 5.4 INTELLECTUAL PROPERTY. All intellectual property, including without limitation, recommendations, specifications, maps, cross-sections, technical data, drawings, plans, calculations, analyses, reports and other documents or digital information prepared by Windsor, its employees and contractors under the Agreement, shall become the property of Permian. At Permian’s request, such intellectual property shall be delivered to Permian upon completion of Windsor’s services under the Agreement. Windsor shall disclose to Permian, promptly and fully, without limitation, any and all useful ideas, concepts, methods, procedures, processes, improvements, prospects, discoveries, and the like (hereinafter collectively referred to as “Developments”) of any nature, made, conceived, or first reduced to practice or use by Windsor as a result of its performance under this Agreement. Unless covered by an appropriate agreement between any third party and Permian, Windsor shall not engage in any activities or use any third-party facilities or intellectual property in performing the services hereunder which could result in claims of ownership to any Developments being made by such third party. All copyrights, patents, trade secrets, or other intellectual property rights associated with any ideas, concepts, techniques, inventions, processes, or works of authorship developed or created by Windsor during the course of performing work for Permian (collectively, the “Work Product”) shall belong exclusively to Permian and, to the extent possible, shall be considered a work made for hire for Permian within the meaning of Title 17 of the United States Code. To the extent the Work Product may not be considered work made for hire for Permian, Windsor agrees to assign, and hereby assigns at the time of creation of the Work Product, without any requirement of further consideration, any right, title, or interest Windsor may have in such Work Product. Upon request of Permian, Windsor shall take such further actions, including execution and delivery of declarations, instruments of conveyance, and the like for any applications or registrations Permian may, at its expense, apply for and as may be appropriate to give full and proper effect to such assignments.

 

Shared Services Agreement – Windsor to Permian – Page 5

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ARTICLE VI

FORCE MAJEURE

SECTION 6.1 PERFORMANCE EXCUSED. Continued performance of a Service may be suspended immediately to the extent caused by any event or condition beyond the reasonable control of the Party suspending such performance including, but not limited to, any act of God, fire, labor or trade disturbance, war, civil commotion, compliance in good faith with any law, unavailability of materials or other event or condition whether similar or dissimilar to the foregoing (each, a “Force Majeure Event”).

SECTION 6.2 NOTICE. The Party claiming suspension due to a Force Majeure Event will give prompt notice to the other Party of the occurrence of the Force Majeure Event giving rise to the suspension and of its nature and anticipated duration.

SECTION 6.3 COOPERATION. The Parties shall cooperate with each other to find alternative means and methods for the provision of the suspended Service.

ARTICLE VII

REPRESENTATIONS AND WARRANTIES

SECTION 7.1 PERMIAN. Permian represents and warrants to Windsor that as of the date of this Agreement:

(a) Permian is a limited liability company duly organized, validly existing, and in good standing under the laws of the State of Delaware and has full power and authority to execute, deliver, and perform this Agreement.

(b) The execution, delivery, and performance of this Agreement have been duly authorized by all necessary action on the part of Permian and do not violate or conflict with its organizational documents, as amended, any material agreement to which Permian or its assets are bound, or any provision of law applicable to Permian.

(c) All consents, authorizations and approvals of, and registrations and declarations with, any governmental authority necessary for the due execution, delivery, and performance of this Agreement have been obtained and are in full force and effect and all conditions thereof have been materially complied with, and no other action by, and no notice to or filing with, any governmental authority is required in connection with the execution, delivery, or performance of this Agreement.

(d) This Agreement constitutes the legal, valid, and binding obligation of Permian enforceable against Permian in accordance with its terms, subject, as to enforcement, to bankruptcy, insolvency, reorganization, and other laws of general applicability relating to or affecting creditors’ rights and to general equity principles.

 

Shared Services Agreement – Windsor to Permian – Page 6

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SECTION 7.2 WINDSOR. Windsor represents and warrants to Permian that as of the date of this Agreement:

(a) Windsor is a limited liability company duly organized, validly existing, and in good standing under the laws of the State of Delaware and has full power and authority to execute, deliver, and perform this Agreement.

(b) The execution, delivery, and performance of this Agreement have been duly authorized by all necessary action on the part of the Windsor and do not violate or conflict with its organizational documents, as amended, any material agreements to which Windsor or its assets are bound, or any provision of law applicable to Windsor.

(c) All consents, authorizations and approvals of, and registrations and declarations with, any governmental authority necessary for the due execution, delivery, and performance of this Agreement have been obtained and are in full force and effect and all conditions thereof have been materially complied with, and no other action by, and no notice to or filing with, any governmental authority is required in connection with the execution, delivery, or performance of this Agreement.

(d) This Agreement constitutes the legal, valid, and binding obligation of Windsor enforceable against Windsor in accordance with its terms, subject, as to enforcement, to bankruptcy, insolvency, reorganization, and other laws of general applicability relating to or affecting creditors’ rights and to general equity principles.

ARTICLE VIII

MISCELLANEOUS

SECTION 8.1 CONSTRUCTION RULES. The article and section headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Words used in this Agreement in the singular, where the context so permits, shall be deemed to include the plural and vice versa. Words used in the masculine or the feminine, where the context so permits, shall be deemed to mean the other and vice versa. The definitions of words in the singular in this Agreement shall apply to such words when used in the plural where the context so permits and vice versa, and the definitions of words in the masculine or feminine in this Agreement shall apply to such words when used in the other form where the context so permits and vice versa. Any reference to a section number in this Agreement shall mean the section number in this Agreement unless otherwise expressly stated. All exhibits attached to this Agreement are hereby incorporated by reference, and any reference to an exhibit in this Agreement shall mean the exhibit attached to this Agreement unless otherwise expressly stated. The words “hereof,” “herein” and “hereunder” and words of similar import referring to this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement.

SECTION 8.2 NOTICES. Any notices or communications required or permitted to be given by this Agreement must be (i) given in writing, and (ii) be personally delivered or mailed by prepaid mail or overnight courier, or by facsimile or electronic transmission delivered or transmitted to the Party to whom such notice or communication is directed, to the address of such Party as follows:

 

Shared Services Agreement – Windsor to Permian – Page 7

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To: Windsor

Windsor Energy Resources LLC

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

Attn: Vice President and CFO

Fax:   (405) 463-6998

To: Permian

Windsor Permian LLC

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

Attn: Vice President and CFO

Fax:   (405) 463-6998

Any such notice or communication shall be deemed to have been given on (i) the day such notice or communication is personally delivered, (ii) three (3) days after such notice or communication is mailed by prepaid certified or registered mail, (iii) one (1) working day after such notice or communication sent by overnight courier, or (iv) the day such notice or communication is faxed or sent electronically and the sender has received a confirmation of such fax or electronic transmission. A Party may, for purposes of this Agreement, change its address, fax number, email address or the person to whom a notice or other communication is marked to the attention of, by giving notice of such change to the other Party pursuant hereto.

SECTION 8.3 ASSIGNMENT; BINDING EFFECT. Neither Party may assign or delegate any of its respective rights, duties or obligations under this Agreement (whether by operation of law or otherwise) without the prior written consent of the other Party; provided, that the foregoing shall in no way restrict the performance of a Service by an Affiliate of Windsor or a third party as otherwise allowed under this Agreement. This Agreement shall be binding upon, and shall inure to the benefit of, the Parties and their respective successors and permitted assigns.

SECTION 8.4 NO THIRD PARTY BENEFICIARIES. Except as specifically set forth in this Agreement, nothing in this Agreement is intended to or shall confer upon any party (other than the Parties) any legal or equitable right, benefit or remedy of any nature whatsoever under or by reason of this Agreement, and no party (except as so specified) shall be deemed a third-party beneficiary under or by reason of this Agreement.

SECTION 8.5 AMENDMENT. No amendment, addition to, alteration, modification or waiver of any part of this Agreement shall be of any effect, whether by course of dealing or otherwise, unless explicitly set forth in writing and executed by the Parties. If the provisions of this Agreement and the provisions of any purchase order or order acknowledgment written in connection with this Agreement conflict, the provisions of this Agreement shall prevail.

 

Shared Services Agreement – Windsor to Permian – Page 8

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SECTION 8.6 WAIVER; REMEDIES. The waiver by a Party of any breach of any provision of this Agreement shall not operate or be construed as a waiver of any subsequent breach. The failure of a Party to require strict performance of any provision of this Agreement shall not affect such Party’s right to full performance thereof at any time thereafter. No right, remedy or election given by any term of this Agreement or made by a Party shall be deemed exclusive, but shall be cumulative with all other rights, remedies and elections available at law or in equity. The Parties acknowledge that the rights created hereby are unique and recognizes and affirms that in the event of a breach of this Agreement irreparable harm would be caused, money damages may be inadequate and an aggrieved Party may have no adequate remedy at law. Accordingly, the Parties agree that the other Party shall have the right, in addition to any other rights and remedies existing in its favor at law or in equity, to enforce such Party’s rights and the obligations of the other Party not only by an action or actions for damages but also by an action or actions for specific performance, injunctive and/or other equitable relief (without posting of a bond or other security).

SECTION 8.7 SEVERABILITY. If any provision contained in this Agreement shall for any reason be held to be invalid, illegal, void or unenforceable in any respect, such provision shall be deemed modified so as to constitute a provision conforming as nearly as possible to the invalid, illegal, void or unenforceable provision while still remaining valid and enforceable and the remaining terms or provisions contained in this Agreement shall not be affected thereby.

SECTION 8.8 MULTIPLE COUNTERPARTS. This Agreement may be executed in one or more counterparts, by facsimile or otherwise, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

SECTION 8.9 RELATIONSHIP OF PARTIES. Notwithstanding the actual relationship between the Parties, this Agreement does not create a fiduciary relationship, partnership, joint venture or relationship of trust or agency between the Parties.

SECTION 8.10 FURTHER ACTIONS. From time to time, the Parties agree to execute and deliver such additional documents, and take such further actions, as may be requested or necessary to carry out the terms of this Agreement.

SECTION 8.11 REGULATIONS. All employees of Windsor and its Affiliates shall, when on the property of Permian, conform to the rules and regulations of Permian concerning safety, health and security which are made known to such employees in advance in writing.

SECTION 8.12 ENTIRE AGREEMENT. This Agreement and the exhibits constitute the entire agreement of the Parties with respect to the subject matter hereof and supersedes and cancels all prior agreements and understandings, either oral or written, between the Parties with respect to the subject matter hereof.

SECTION 8.13 CONSTRUCTION. In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted by the Parties, and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement.

 

Shared Services Agreement – Windsor to Permian – Page 9

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SECTION 8.14 GOVERNING LAW; VENUE; JURISDICTION. All issues and questions concerning the construction, validity, enforcement and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Oklahoma, without giving effect to any choice of law or conflict of law rules or provisions (whether of the State of Oklahoma or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Oklahoma. The Parties further agree that any dispute arising out of this Agreement shall be decided by either the state or federal court in Oklahoma County, Oklahoma. The Parties shall each submit to the jurisdiction of those courts and agree that service of process by certified mail, return receipt requested, shall be sufficient to confer said courts with in personam jurisdiction.

SECTION 8.15 LIMITATION OF LIABILITY. UNDER NO CIRCUMSTANCES AND UNDER NO LEGAL OR EQUITABLE THEORY, WHETHER IN TORT, CONTRACT, STRICT LIABILITY OR OTHERWISE, SHALL EITHER PARTY, ITS AFFILIATES OR THEIR RESPECTIVE SHAREHOLDERS, MEMBERS, PARTNERS, DIRECTORS, MANAGERS, OFFICERS, EMPLOYEES OR AGENTS BE LIABLE TO THE OTHER PARTY OR TO ANY OTHER PERSON FOR ANY INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL LOSSES OR DAMAGES OF ANY NATURE ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT OR THE SERVICES INCLUDING, BUT NOT LIMITED TO, DAMAGES FOR LOST MARKETING, LOST PROFITS, LOSS OF GOODWILL, LOSS OF DATA OR WORK STOPPAGE, EVEN IF AN AUTHORIZED REPRESENTATIVE OF SUCH PARTY HAS BEEN ADVISED OF OR SHOULD HAVE KNOWN OF THE POSSIBILITY OF SUCH DAMAGES. WINDSOR’S LIABILITY HEREUNDER SHALL BE LIMITED TO THE AMOUNT OF FEES RECEIVED FROM PERMIAN.

SECTION 8.16 DISCLAIMER. EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES PROVIDED IN THIS AGREEMENT, WINDSOR MAKES NO OTHER WARRANTY, EITHER EXPRESS OR IMPLIED, WRITTEN, OR ORAL REGARDING THE SERVICES PROVIDED HEREUNDER INCLUDING, BUT NOT LIMITED TO, THE WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT, TITLE, CUSTOM, TRADE AND QUIET ENJOYMENT.

SECTION 8.17 WAIVER OF JURY TRIAL. THE PARTIES HEREBY WAIVE ANY RIGHT TO TRIAL BY JURY OF ANY ISSUE TRIABLE BY A JURY FULLY TO THE EXTENT THAT ANY SUCH RIGHT NOW OR HEREAFTER EXISTS WITH REGARD TO THIS AGREEMENT, OR ANY CLAIM, COUNTERCLAIM OR OTHER ACTION ARISING IN CONNECTION THEREWITH. THIS WAIVER OF RIGHT TO TRIAL BY JURY IS GIVEN KNOWINGLY AND VOLUNTARILY BY THE PARTIES AND IS INTENDED TO ENCOMPASS INDIVIDUALLY EACH INSTANCE AND EACH ISSUE AS TO WHICH THE RIGHT TO A TRIAL BY JURY MAY OTHERWISE ACCRUE. THE PARTIES ARE EACH HEREBY AUTHORIZED TO FILE A COPY OF THIS SECTION IN ANY PROCEEDING AS CONCLUSIVE EVIDENCE OF THIS WAIVER BY THE OTHER PARTY.

 

Shared Services Agreement – Windsor to Permian – Page 10

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IN WITNESS WHEREOF, the Parties have executed and delivered this Agreement effective as of the day and year first written above.

 

“WINDSOR”				WINDSOR ENERGY RESOURCES LLC, a Delaware limited liability company
				By:		/s/ Robert N. Fitzgerald
						Name: Robert N. Fitzgerald
						Title:   Vice President and CFO
“PERMIAN”				WINDSOR PERMIAN LLC, a Delaware limited liability company
				By:		/s/ William C. Liedtke III
						Name: William C. Liedtke III
						Title:   Vice President and General Counsel

 

Shared Services Agreement – Windsor to Permian – Page 11

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EXHIBIT “A”

SCHEDULE OF SERVICES

WINDSOR PERMIAN LLC

Windsor personnel will provide consulting, technical and administrative services including, but not limited to those activities required to provide the following services:

Production operations—the engineering, land, geological, and administrative services required to operating and evaluate the performance of company operating wells and related activities necessary to find, lift and market oil and gas.

Drilling and development—the engineering, land, geological, and administrative services required to operating and evaluate the performance of company operating wells and related activities necessary to find, lift and market oil and gas.

Exploration—the engineering, land, geological, and administrative services required to identify oil and gas leases, either producing or non-producing, including maintenance of land records and rental payments, geological assessments and evaluations and other exploratory activities.

Acquisition and divestment activities—those technical and administrative activities required to acquire oil and gas assets or to sell oil and gas investments.

Operated by Others (OBO) management—all administrative and technical reviews and accounting of OBO assets owned by PERMIAN and associated reporting and assessments of the assets.

SCHEDULE OF COMPENSATION

Windsor will provide the necessary human resources and related overhead support to provide the activities listed above. Windsor will prepare an estimate of the costs to support these functions each year on January 1st and may revise the costs by submitting a written adjustment to PERMIAN of any material cost changes.

Windsor will prepare a monthly statement of activities to allocate its costs without markup for expenses incurred based upon actual costs. Costs will be captured by the services provided and allocated to PERMIAN based upon key metrics identified as part of the annual budgeting process.

Cost will be charged on a monthly basis and reimbursed to Windsor within 10 business days. Windsor reserves the right to cash advance PERMIAN for semi-monthly payroll costs as deemed necessary by Windsor.

 

Shared Services Agreement – Windsor to Permian – Page 12

Exhibit 10.8

LEASE AMENDMENT #1

WINDSOR PERMIAN, LLC

FASKEN MIDLAND, LLC., (hereinafter called “Lessor”) and WINDSOR PERMIAN, LLC, (hereinafter called “Lessee”), for good and valuable consideration the receipt of which is hereby acknowledged, do hereby amend that certain Lease Agreement dated April 19, 2011 covering approximately 1,586 square feet of Net Rentable Area located on Level Twelve (12) of One Fasken Center at 500 West Texas Avenue, Midland, Texas 79701, also known as Suite 1210, under the following terms and conditions:

 

1.

LEASED PREMISES. Effective November 1, 2011, the provisions of paragraph 1.5 are hereby deleted and the following substituted in lieu thereof:

Approximately 3,075 square feet of Net Rentable Area in the Building as more fully diagrammed on the floor plans of such premises attached hereto and made a part hereof as “Exhibit B-l”, on the floor(s) indicated thereon, together with a common area percentage factor determined by Lessor (the “Leased Premises”). Said Leased Premises is comprised of approximately 1,586 square feet of Net Rentable Area in the Original Leased Premises together with approximately 1,489 square feet of Net Rentable Area (the “Suite 1220 Expansion Space”). Said demised space represents approximately 0.729% of the Total Net Rentable Area, such Total Net Rentable Area of the Building being approximately 421,546 square feet.

 

2.

RENT. The Base Rent for the Leased Premises shall be as follows:

 

PERIOD		ANNUAL RATE				ANNUAL BASE RENT				MONTHLY BASE RENT
11/1/11-5/31/12		$	16.00			$	49,200.00			$	4,100.00
6/1/12-5/31/13		$	16.75			$	51,506.25			$	4,292.19
6/1/13-5/31/14		$	17.50			$	53,812.50			$	4,484.38
6/1/14-5/31/15		$	18.25			$	56,118.75			$	4,676.56
6/1/15-5/31/16		$	19.00			$	58,425.00			$	4,868.75

 

3.

SUBJECT TO VACATING. Lessor’s duty to tender possession of the Suite 1220 Expansion Space added to the Leased Premises hereunder is subject to the current tenant vacating Suite 1220; Provided, however, that if the current tenant does not vacate Suite 1220 within six (6) months from the proposed effective date hereof, Lessee shall have the right to terminate its obligation to lease Suite 1220 by delivery of written notification to Lessor.

 

4.

RATIFICATION. Lessor and Lessee do hereby ratify and affirm all of the terms, conditions and covenants of the Lease Agreement, as amended herein.

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Witness the execution hereby this the 6^th day of June, 2011 but to be effective November 1, 2011.

 

LESSOR						LESSEE
FASKEN MIDLAND, LLC						WINDSOR PERMIAN, LLC
By:		JB Fund 1, LLC, Manager				By:		/s/ Travis D. Stice
By:		Its Managers				Name:		Travis D. Stice
		North Waterfront Corporation				Title:		President & COO
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President
JB Financials, Inc.
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President

 

2

Exhibit 10.9

LEASE AMENDMENT #2

WINDSOR PERMIAN LLC

FASKEN MIDLAND, LLC., (hereinafter called “Lessor”) and WINDSOR PERMIAN LLC, (hereinafter called “Lessee”), for good and valuable consideration the receipt of which is hereby acknowledged, do hereby amend that certain Lease Agreement dated April 19, 2011 and Lease Amendment #1 dated June 6, 2011 covering approximately 3,075 square feet of Net Rentable Area located on Level Twelve (12) of One Fasken Center at 500 West Texas Avenue, Midland, Texas 79701, also known as Suite 1210, under the following terms and conditions:

 

1.

LEASED PREMISES. Effective August 1, 2011, the provisions of paragraph 1.5 are hereby deleted and the following substituted in lieu thereof:

Approximately 3,581 square feet of Net Rentable Area located on Levels Twelve (12) and Basement in the Building as more fully diagrammed on the floor plans of such premises attached hereto and made a part hereof as “Exhibit B—l” and “Exhibit B—2”, on the floors indicated thereon, together with a common area percentage factor determined by Lessor (the “Leased Premises”). Said Leased Premises is comprised of approximately 1,586 square feet of Net Rentable Area in the Original Leased Premises together with approximately 1,995 square feet of Net Rentable Area (the “Basement Expansion Space”). Said demised space represents approximately 0.849% of the Total Net Rentable Area, such Total Net Rentable Area of the Building being approximately 421,546 square feet.

Effective November 1, 2011, the provisions of paragraph 1.5 are hereby deleted and the following substituted in lieu thereof:

Approximately 5,070 square feet of Net Rentable Area located on Levels Twelve (12) and Basement in the Building as more fully diagrammed on the floor plans of such premises attached hereto and made a part hereof as “Exhibit B—l” and “Exhibit B—2”, on the floors indicated thereon, together with a common area percentage factor determined by Lessor (the “Leased Premises”). Said Leased Premises is comprised of approximately 1,586 square feet of Net Rentable Area in the Original Leased Premises together with approximately 1,995 square feet of Net Rentable Area (the “Basement Expansion Space”) and approximately 1,489 square feet of Net Rentable Area (the “Suite 1220 Expansion Space”). Said demised space represents approximately 1.203% of the Total Net Rentable Area, such Total Net Rentable Area of the Building being approximately 421,546 square feet.

 

2.

TERM. The Lease term for the Basement Expansion Space added by this amendment shall be on a month to month basis, commencing August 1, 2011 and automatically renewing on the first day of each month thereafter until Termination, as defined herein. The Lease term for the other space shall remain unchanged.

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3.

RENT. Effective August 1, 2011, the Base Rent table set forth on Exhibit C of the Lease and Section 2 (Rent) of Amendment #1 and are hereby deleted and the attached Exhibit C—l shall be substituted in lieu thereof.

 

4.

TERMINATION. This Lease Amendment #2 may be terminated by either Lessor or Lessee, for any reason or no reason, on the last day of any calendar month by providing written notice to the other at least thirty (30) days prior to the last day of such month. If Lessor, in Lessor’s sole discretion, finds Lessee in default of this agreement or any of the building rules and regulations, Lessor may terminate this Lease Amendment #2 immediately upon the expiration of ten (10) days following a written notice to cure to Lessee if Lessee fails to cure the default; provided that Lessor shall not be able to terminate this Lease Amendment #2 should Lessee have commenced to cure such default within said ten (10) day period and thereafter proceeds with diligence to cure same.

 

5.

SUBJECT TO VACATING. Lessor’s duty to tender possession of the Basement Expansion Space added to the Leased Premises hereunder is subject to the current tenant vacating the Basement Expansion Space. Provided, however, that if the current tenant does not vacate the Basement Expansion Space within six (6) months from the proposed effective date hereof, Lessee shall have the right to terminate its obligation to lease the Basement Expansion Space by delivery of written notification to Lessor.

 

6.

FINISH OUT. Lessee accepts the Leased Premises in “as is” condition and no other finish out shall be required of Lessor. Any alterations to the Leased Premises shall be at Lessee’s sole expense and responsibility.

 

7.

RATIFICATION. Lessor and Lessee do hereby ratify and affirm all of the terms, conditions and covenants of the Lease Agreement, as amended herein.

Witness the execution hereby this the 5^th day of August, 2011 but to be effective August 1, 2011.

 

LESSOR						LESSEE
FASKEN MIDLAND, LLC						WINDSOR PERMIAN, LLC
By:		JB Fund 1, LLC, Manager				By:		/s/ Travis D. Stice
By:		Its Managers				Name:		Travis D. Stice
		North Waterfront Corporation				Title:		President & COO
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President

 

2

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JB Financials, Inc.
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President

 

3

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LEASE AMENDMENT #2

WINDSOR PERMIAN LLC

EXHIBIT C – 1

 

Sq. Ft.		Original Leased Premises - Suite 1210 - 1,586 Sq. Ft.												Suite 1220 Expansion Space - 1,489 Sq. Ft.
Months		Annual Rate Per SF for Original Leased Premises				Annual Rent for Original Leased Premises				Monthly Rent for Original Leased Premises				Annual Rate Per SF for Suite 1220 Expansion Space						Annual Rent for Suite 1220 Expansion Space		Monthly Rent for Suite 1220 Expansion Space				Total Annual Rent for Suite 1210 and Suite 1220				Total Monthly Rent for Suite 1210 and Suite 1220				Additional Monthly Rent for Basement Expansion Space
8/1/11 until Termination of Amendment #2 for Basement Expansion Space																																		$	2,826.25
08/01/11—10/31/11		$	16.00			$	25,376.00			$	2,114.67															$	25,376.00			$	2,114.67
11/1/11—5/31/12		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$23,824.00				$	1,985.33			$	49,200.00			$	4,100.00
6/1/12—5/31/13		$	16.75			$	26,565.50			$	2,213.79			$	16.75			$24,940.75				$	2,078.40			$	51,506.25			$	4,292.19
6/1/2013—5/31/14		$	17.50			$	27,755.00			$	2,312.92			$	17.50			$26,057.50				$	2,171.46			$	53,812.50			$	4,484.38
06/01/14—05/31/15		$	18.25			$	28,944.50			$	2,412.04			$	18.25			$27,174.25				$	2,264.52			$	56,118.75			$	4,676.56
06/01/15—05/31/16		$	19.00			$	30,134.00			$	2,511.17			$	19.00			$28,291.00				$	2,357.58			$	58,425.00			$	4,868.75

Exhibit 10.10

LEASE AMENDMENT #3

WINDSOR PERMIAN LLC

FASKEN MIDLAND, LLC., (hereinafter called “Lessor”) and WINDSOR PERMIAN, LLC, (hereinafter called “Lessee”), for good and valuable consideration the receipt of which is hereby acknowledged, do hereby amend that certain Lease Agreement dated April 19, 2011 and Lease Amendment #1 dated June 6, 2011 and Amendment #2 dated August 5, 2011 covering approximately 5,070 square feet of Net Rentable Area located on Levels Twelve (12) and Basement of One Fasken Center at 500 West Texas Avenue, Midland, Texas 79701, also known as Suite 1210, under the following terms and conditions:

 

1.

LEASED PREMISES. Effective December 1, 2011, the provisions of paragraph 1.5 are hereby deleted and the following substituted in lieu thereof:

Approximately 7,067 square feet of Net Rentable Area located on Levels Twelve (12) and Basement in the Building as more fully diagrammed on the floor plans of such premises attached hereto and made a part hereof as “Exhibit B—l” and “Exhibit B—2”, on the floors indicated thereon, together with a common area percentage factor determined by Lessor (the “Leased Premises”). Said Leased Premises is comprised of approximately 1,586 square feet of Net Rentable Area in the Original Leased Premises together with approximately 1,995 square feet of Net Rentable Area (the “Basement Expansion Space”), approximately 1,489 square feet of Net Rentable Area (the “Suite 1220 Expansion Space”) and approximately 1,997 square feet of Net Rentable Area (the “Suite 1225 Expansion Space”). Said demised space represents approximately 1.676% of the Total Net Rentable Area, such Total Net Rentable Area of the Building being approximately 421,546 square feet.

 

2.

TERM. The Lease term for the Suite 1225 Expansion Space added by this amendment shall be for four (4) years and six (6) months, commencing December 1, 2011 and terminating May 31, 2016.

 

3.

RENT. Effective December 1, 2011, the Base Rent table set forth on Exhibit C of the Lease, Section 2 (Rent) of Amendment #1 and Exhibit C—1 of Amendment #2 are hereby deleted and the attached Exhibit C—2 shall be substituted in lieu thereof.

 

4.

PARKING. Effective December 1, 2011, the provisions of paragraph 1.14 are hereby deleted and the following substituted in lieu thereof:

Lessor agrees to provide up to five (5) additional parking spaces in the attached parking garage, at the following rates per space per month plus applicable sales tax at Lessee’s election herein:

            @ $95.00 per space per month for Officer Reserved (Basement & Level One) – space may be limited, if available

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            @ $75.00 per space per month for Preferred Reserved (Level Two and above) – space may be limited, if available

            @ $55.00 per space per month for General Unreserved    

The parking spaces set forth in this section shall be for Lessee and/or Lessee’s employees and Lessor shall have the right to assign parking space as conditions permit. However, Lessor shall not be required to police the use of these spaces. Lessor may make, modify and enforce rules and regulations relating to the parking of automobiles in the parking area(s), and Lessee shall abide thereby. Lessor shall not be liable to Lessee or Lessee’s agents, servants, employees, customers, or invitees for damage to person or property caused by any act of omission or neglect of Lessee, and Lessee agrees to hold Lessor harmless from all claims for any such damage.

 

5.

SUBJECT TO VACATING. Lessor’s duty to tender possession of the Suite 1225 Expansion Space added to the Leased Premises hereunder is subject to the current tenant vacating the Suite 1225 Expansion Space. Provided, however, that if the current tenant does not vacate the Suite 1225 Expansion Space within six (6) months from the proposed effective date hereof, Lessee shall have the right to terminate its obligation to lease the Suite 1225 Expansion Space by delivery of written notification to Lessor.

 

6.

FINISH OUT. Lessee accepts the Leased Premises in “as is” condition and no other finish out shall be required of Lessor. Any alterations to the Leased Premises shall be at Lessee’s sole expense and responsibility.

 

7.

RATIFICATION. Lessor and Lessee do hereby ratify and affirm all of the terms, conditions and covenants of the Lease Agreement, as amended herein.

Witness the execution hereby this the 28^th day of September, 2011 but to be effective December 1, 2011.

 

2

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LESSOR						LESSEE
FASKEN MIDLAND, LLC						WINDSOR PERMIAN, LLC
By:		JB Fund 1, LLC, Manager				By:		/s/ Travis D. Stice
By:		Its Managers				Name:		Travis D. Stice
		North Waterfront Corporation				Title:		President & COO
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President
JB Financials, Inc.
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper
		Vice President

 

3

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LEASE AMENDMENT #2

WINDSOR PERMIAN LLC

EXHIBIT C – 2

 

Sq. Ft.		Original Leased Premises - Suite 1210 - 1,586 Sq. Ft.												Suite 1220 Expansion Space - 1,489 Sq. Ft.												Suite 1225 Expansion Space - 1,997 Sq. Ft.
Months		Annual Rate Per SF for Original Leased Premises				Annual Rent for Original Leased Premises				Monthly Rent for Original Leased Premises				Annual Rate Per SF for Suite 1220 Expansion Space				Annual Rent for Suite 1220 Expansion Space				Monthly Rent for Suite 1220 Expansion Space				Annual Rate Per SF for Suite 1225 Expansion Space				Annual Rent for Suite 1225 Expansion Space				Monthly Rent for Suite 1225 Expansion Space				Total Annual Rent for Suite 1210, 1220 and 1225				Total Monthly Rent for Suite 1210, 1220 and 1225				Additional Monthly Rent for Basement Expansion Space
8/1/11 until Termination of Amendment #2 for Basement Expansion Space																																														$	2,826.25
08/01/11—10/31/11		$	16.00			$	25,376.00			$	2,114.67																											$	25,376.00			$	2,114.67
11/1/11—11/30/11		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$	23,824.00			$	1,985.33															$	49,200.00			$	4,100.00
12/1/11—5/31/12		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$	23,824.00			$	1,985.33			$	18.00			$	35,946.00			$	2,995.50			$	85,146.00			$	7,095.50
6/1/12—5/31/13		$	16.75			$	26,565.50			$	2,213.79			$	16.75			$	24,940.75			$	2,078.40			$	18.50			$	36,944.50			$	3,078.71			$	88,450.75			$	7,370.90
6/1/13—5/31/14		$	17.50			$	27,755.00			$	2,312.92			$	17.50			$	26,057.50			$	2,171.46			$	19.00			$	37,943.00			$	3,161.92			$	91,755.50			$	7,646.29
06/10/14—05/31/15		$	18.25			$	28,944.50			$	2,412.04			$	18.25			$	27,174.25			$	2,264.52			$	20.00			$	39,940.00			$	3,328.33			$	96,058.75			$	8,004.90
06/01/15—05/31/16		$	19.00			$	30,134.00			$	2,511.27			$	19.00			$	28,291.00			$	2,357.58			$	21.00			$	41,937.00			$	3,494.75			$	100,362.00			$	8,363.50

Exhibit 10.11

LEASE AMENDMENT #4

WINDSOR PERMIAN LLC

FASKEN MIDLAND, LLC., (hereinafter called “Lessor”) and WINDSOR PERMIAN LLC, (hereinafter called “Lessee”), for good and valuable consideration the receipt of which is hereby acknowledged, do hereby amend that certain Lease Agreement dated April 19, 2011 and Lease Amendment #1 dated June 6, 2011, Amendment #2 dated August 5, 2011 and Amendment #3 covering approximately 7,067 square feet of Net Rentable Area located on Levels Twelve (12) and Basement of One Fasken Center at 500 West Texas Avenue, Midland, Texas 79701, also known as Suite 1210, under the following terms and conditions:

 

1.

LEASED PREMISES. Effective February 1, 2012, the provisions of paragraph 1.5 are hereby deleted and the following substituted in lieu thereof:

Approximately 7,381 square feet of Net Rentable Area located on Levels Twelve (12) and Basement in the Building as more fully diagrammed on the floor plans of such premises attached hereto and made a part hereof as “Exhibit B-l” and “Exhibit B-2”, on the floors indicated thereon, together with a common area percentage factor determined by Lessor (the “Leased Premises”). Said Leased Premises is comprised of approximately 1,586 square feet of Net Rentable Area in the Original Leased Premises together with approximately 1,995 square feet of Net Rentable Area (the “Basement Expansion Space”), approximately 1,489 square feet of Net Rentable Area (the “Suite 1220 Expansion Space”), approximately 1,997 square feet of Net Rentable Area (the “Suite 1225 Expansion Space”) and 314 square feet of Net Rentable Area (the 12th Floor Expansion Space”). Said demised space represents approximately 1.751% of the Total Net Rentable Area, such Total Net Rentable Area of the Building being approximately 421,546 square feet.

 

2.

TERM. The Lease term for the 12th Floor Expansion Space added by this amendment shall be for four (4) years and four (4) months, commencing February 1, 2012 and terminating May 31, 2016.

 

3.

RENT. Effective February 1, 2012, the Base Rent table set forth on Exhibit C of the Lease, Section 2 (Rent) of Amendment #1, Exhibit C-l of Amendment #2 and Exhibit C-2 of Amendment #3 are hereby deleted and the attached Exhibit C- 3 shall be substituted in lieu thereof.

 

4.

FINISH OUT. Lessee accepts the Leased Premises in “as is” condition and no other finish out shall be required of Lessor. Any alterations to the Leased Premises shall be at Lessee’s sole expense and responsibility.

 

5.

RATIFICATION. Lessor and Lessee do hereby ratify and affirm all of the terms, conditions and covenants of the Lease Agreement, as amended herein.

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Witness the execution hereby this the 6th day of February, 2012 but to be effective February 1, 2012.

 

LESSOR   FASKEN MIDLAND, LLC By: JB Fund 1, LLC, Manager By: Its Managers North Waterfront Corporation						LESSEE   WINDSOR PERMIAN LLC
By:		/s/ Thomas E. Cooper				By:				/s/ Travis D. Stice
		Thomas E. Cooper						Name:		Travis D. Stice
		Vice President						Title:		President & CEO
By:		/s/ Thomas E. Cooper
		Thomas E. Cooper Vice President

 

2

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WINDSOR PERMIAN LLC

EXHIBIT C-3

 

		Original Leased Premises – Suite 1210 – 1,586 Sq. Ft.												Suite 1220 Expansion Space – 1,489 Sq. Ft.												Suite 1225 Expansion Space – 1,997 Sq. Ft.												12th Floor Expansion Space – 314 Sq. Ft.
Months		Annual Rate Per SF for Original Leased Premises				Annual Rent for Original Leased Premises				Monthly Rent for Original Leased Premises				Annual Rate Per SF for Suite 1220 Expansion Space				Annual Rent for Suite 1220 Expansion Space				Monthly Rent for Suite 1220 Expansion Space				Annual Rate Per SF for Suite 1225 Expansion Space				Annual Rent for Suite 1225 Expansion Space				Monthly Rent for Suite 1225 Expansion Space				Annual Rate Per SF for 12th Floor Expansion Space				Annual Rent for 12th floor Expansion Space				Monthly Rent for 12th Floor Expansion Space				Total Annual Rent for Suite 1210, 1220,1225 and 12th Fl.				Total Monthly Rent for Suite 1210, 1220,1225 and 12th Fl.				Additional Monthly Rent for Basement Expansion Space
8/1/11 until Termination of Amendment #2 for Basement Expansion Space																																																										$	2,826.25
08/01/11—10/31/11		$	16.00			$	25,376.00			$	2,114.67																																							$	25,376.00			$	2,114.67
11/1/11—11/30/11		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$	23,824.00			$	1,985.33																											$	49,200.00			$	4,100.00
12/1/11—1/31/12		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$	23,824.00			$	1,985.33			$	18.00			$	35,946.00			$	2,995.50															$	85,146.00			$	7,095.50
2/1/12—5/31/12		$	16.00			$	25,376.00			$	2,114.67			$	16.00			$	23,824.00			$	1,985.33			$	18.00			$	35,946.00			$	2,995.50			$	19.00			$	5,966.00			$	497.17			$	91,112.00			$	7,592.67
6/1/12—5/31/13		$	16.75			$	26,565.50			$	2,213.79			$	16.75			$	24,940.75			$	2,078.40			$	18.50			$	36,944.50			$	3,078.71			$	19.50			$	6,123.00			$	510.25			$	94,573.75			$	7,881.15
6/1/2013—5/31/14		$	17.50			$	27,755.00			$	2,312.92			$	17.50			$	26,057.50			$	2,171.46			$	19.00			$	37,943.00			$	3,161.92			$	20.00			$	6,280.00			$	523.33			$	98,035.50			$	8,169.63
06/01/14—05/31/15		$	18.25			$	28,944.50			$	2,412.04			$	18.25			$	27,174.25			$	2,264.52			$	20.00			$	39,940.00			$	3,328.33			$	21.00			$	6,594.00			$	549.50			$	102,652.75			$	8,554.40
06/01/15—05/31/16		$	19.00			$	30,134.00			$	2,511.17			$	19.00			$	28,291.00			$	2,357.58			$	21.00			$	41,937.00			$	3,494.75			$	22.00			$	6,908.00			$	575.67			$	107,270.00			$	8,939.17

 

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EXHIBIT 10.16

FORM OF

ADVISORY SERVICES AGREEMENT

ADVISORY SERVICES AGREEMENT dated as of                 , 2012 (this “Agreement”), between DIAMONDBACK ENERGY, INC., a Delaware corporation (the “Company”), and WEXFORD CAPITAL LP, a Delaware limited partnership (“Wexford”).

Whereas, during the period from the formation of Windsor Permian LLC (“Windsor Permian”) through its contribution to the Company in connection with the Company’s initial public offering, Wexford served as the manager of Windsor Permian and certain of its affiliates and, as a result, has extensive background and familiarity with the Company, its business and assets; and

Whereas, Wexford has extensive knowledge and experience with respect to managing public and private businesses, capital markets transactions, financing transactions, long range planning and business development and other matters that are significant to the future business and operations of the Company; and

Whereas, the Company desires to benefit from Wexford’s expertise and has requested that Wexford provide assistance and advise to the Company from time to time with respect to certain financial and strategic matters related to the business and affairs of the Company and its subsidiaries; and

Whereas, Wexford has agreed to the Company’s request on the terms and conditions specified herein.

NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged the Company and Wexford agree as follows:

Section 1. Retention of Wexford.

The Company hereby retains Wexford, and Wexford accepts such retention, upon the terms and conditions set forth in this Agreement.

Section 2. Term; Termination.

(a) This Agreement shall commence on the closing date of the Company’s initial public offering and shall terminate on the second anniversary thereof (the “Initial Term”), unless extended as provided in this Section 2. The parties may by mutual agreement extend the then current Term for additional one-year periods by entering into a written agreement reflecting the terms of such extension at least ten days prior to the expiration of the then current Term (such extension period being referred to herein as the “Extension Term,” and together with the Initial Term, collectively, the “Term”).

(b) Termination. This Agreement may be terminated by either party at any time, with or without cause, upon 30 days’ prior written notice to the other party. In the event of termination, the Company shall be obligated to pay all amounts due to Wexford through the termination date. The provisions set forth in Section 5 of this Agreement shall survive any termination of this Agreement.

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Section 3. Advisory Services.

(a) Wexford shall advise the Company concerning such matters that relate to financial and strategic matters of the Company and its subsidiaries (the “Services”), in each case as the Company shall reasonably request by way of notice to Wexford. The Services shall not extend to the day-to-day business or operations of the Company and shall not include any services provided by officers or employees in their capacity as directors of the Company. If requested to provide Services, Wexford shall devote such time to any such request as Wexford shall deem, in its sole discretion, necessary. Such Services, in Wexford’s sole discretion, shall be rendered in person or by telephone or other communication. Wexford shall have no obligation to the Company as to the manner of rendering the Services hereunder, and the Company shall not have any right to dictate or direct the details of the Services rendered hereunder.

(b) Wexford shall perform all Services to be provided hereunder as an independent contractor to the Company and not as an employee, agent or representative of the Company. Wexford shall have no authority to act for or to bind the Company without its prior written consent. Nothing in this Agreement is intended nor shall be deemed to create any partnership, agency or joint venture relationship by or between the parties.

(c) This Agreement shall not prohibit, restrict or limit in any manner Wexford or any of its partners or Affiliates or any director, officer, partner or employee of Wexford or any of its partners or Affiliates (collectively, “Wexford Persons”) from engaging in other activities, whether or not competitive with any business of the Company or any of its respective subsidiaries or Affiliates. This Agreement shall not require Wexford or any Wexford Person to make available to the Company any investment or investment opportunity about which Wexford or any Wexford Person shall become aware.

(d) In the event the Company is dissatisfied in any manner with the Services provided by Wexford hereunder or with Wexford’s performance under this Agreement, the Company’s sole remedy shall be to terminate this Agreement. Under no circumstances shall the Company have any claim for damages against Wexford or any Wexford Person arising out of or relating to this Agreement.

Section 4. Compensation.

(a) Advisory Fee. As consideration for the Services provided by Wexford hereunder, the Company agrees to pay to Wexford an annual fee in the amount of $500,000 payable in advance in equal monthly installments, on the first business day of each month during the Term and prorated for any partial calendar month (the “Consulting Fee”).

(b) Expenses. Upon presentation by Wexford to the Company of such documentation as may be reasonably requested by the Company, the Company shall reimburse Wexford for all reasonable out-of-pocket expenses, including, without limitation, reasonable legal fees and expenses, and other disbursements incurred by Wexford or any Wexford Person in the performance of Wexford’s obligations hereunder.

 

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(c) Additional Services. If the Company requests that Wexford provide services in addition to the Services, such as those relating to proposed acquisitions or divestitures, and Wexford agrees to provide such additional services, the Company and Wexford shall negotiate the additional market-based fees to be paid by the Company to Wexford or its Affiliates for such additional services, which fees shall be approved by the Company’s independent directors.

(d) Non-Exclusive. Nothing in this Agreement shall have the effect of prohibiting Wexford or any of its Affiliates from receiving from the Company or any of its subsidiaries or Affiliates any other fees.

Section 5. Indemnification.

(a) The Company will indemnify and hold harmless Wexford and each Wexford Person (each such person, an “Indemnified Party”) from and against any and all losses, claims, damages, liabilities, costs and expenses, whether joint or several (the “Liabilities”), related to, arising out of or in connection with this Agreement or the Services contemplated by this Agreement or the engagement of Wexford pursuant to, and the performance Wexford of the Services contemplated by, this Agreement, whether or not pending or threatened, whether or not an Indemnified Party is a party, whether or not resulting in any liability and whether or not such action, claim, suit, investigation or proceeding is initiated or brought by or on behalf of the Company. The Company will reimburse any Indemnified Party for all reasonable costs and expenses (including attorneys’ fees and expenses) as they are incurred in connection with investigating, preparing, pursuing, defending or assisting in the defense of any action, claim, suit, investigation or proceeding for which the Indemnified Party would be entitled to indemnification under the terms of the previous sentence, or any action or proceeding arising therefrom, whether or not such Indemnified Party is a party thereto. The Company will not be liable under the foregoing indemnification provision with respect to any particular Liability of an Indemnified Party solely to the extent that such is determined by a court, in a final judgment from which no further appeal may be taken, to have resulted primarily from the gross negligence or willful misconduct of such Indemnified Party. The attorneys’ fees and other expenses of an Indemnified Party shall be paid by the Company as they are incurred upon receipt of an agreement by or on behalf of the Indemnified Party to repay such amounts if it is finally judicially determined that the Liabilities in question resulted primarily from the gross negligence or willful misconduct of such Indemnified Party.

(b) The Company acknowledges and agrees that the Indemnified Parties have certain rights to indemnification and/or insurance provided by Wexford and certain of its affiliates and that such additional rights to indemnification and/or insurance are intended to be secondary to the primary obligation of the Company to indemnify the Indemnified Parties hereunder. The Company’s obligations to provide indemnification hereunder shall not be limited in any manner by the availability of such additional indemnification and/or insurance that may be available to the Indemnified Parties.

 

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Section 6. Accuracy of Information.

The Company shall furnish or cause to be furnished to Wexford such information as Wexford believes reasonably appropriate in connection with providing the services contemplated by this Agreement (all such information so furnished, the “Information”). The Company recognizes and confirms that Wexford (a) will use and rely primarily on the Information and on information available from generally recognized public sources in performing the services contemplated by this Agreement without independent verification, (b) does not assume responsibility for the accuracy or completeness of the Information and such other information and (c) is entitled to rely upon the Information without independent verification.

Section 7. Notices.

All notices, requests, consents and other communications hereunder shall be in writing and shall be deemed sufficient if personally delivered, sent by nationally-recognized overnight courier, or by registered or certified mail, return receipt requested and postage prepaid, addressed as follows:

 

(a)

if to Wexford, to:

Wexford Capital LP

411 West Putnam Avenue

Greenwich, CT 06830

Attention:          Jay Maymudes, CFO

Telephone:        203 862 7050

with a copy to:

Wexford Capital LP

411 West Putnam Avenue

Greenwich, CT 06830

Attention:        Arthur Amron, General Counsel

Telephone:      (203) 862-7012

 

(b)

if to the Company, to:

Diamondback Energy, Inc.

500 West Texas

Suite 1225

Midland, TX 79701

Attention:       Travis Stice

Telephone:      (432) 221-7400

 

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with a copy to:

Diamondback Energy, Inc.

14301 Caliber Drive

Suite 300

Oklahoma City, OK 73134

Attention:        Randal Holder

Telephone:      (405) 463-6932

or to such other address as the party to whom notice is to be given may have furnished to each other party in writing in accordance herewith. Any such notice or communication shall be deemed to have been received (i) in the case of personal delivery, on the date of such delivery, (ii) in the case of nationally-recognized overnight courier guaranteeing next day delivery, on the next business day after the date when sent, and (iii) in the case of mailing, on the fifth business day following that on which the piece of mail containing such communication is posted.

Section 8. Benefits of Agreement.

This Agreement shall bind and inure to the benefit of Wexford, the Company, the Indemnified Persons and any successors to or assigns of Wexford and the Company; provided, however, that this Agreement may not be assigned by the Company without the prior written consent of Wexford.

Section 9. Governing Law.

This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York (without giving effect to principles of conflicts of laws).

Section 10. Headings.

Section headings are used for convenience only and shall in no way affect the construction of this Agreement.

Section 11. Entire Agreement; Amendments.

This Agreement contains the entire understanding of the parties with respect to its subject matter and supersedes any and all prior agreements, and neither it nor any part of it may in any way be altered, amended, extended, waived, discharged or terminated except by a written agreement that specifically references this Agreement and the provisions to be so altered, amended, extended, waived, discharged or terminated is signed by each of the parties hereto and specifically states that it is intended to alter, amend, extend, waive, discharge or terminate this agreement or a provision hereof.

Section 12. Counterparts.

This Agreement may be executed and delivered (including by facsimile transmission) in any number of counterparts, and each such counterpart shall be deemed to be an original instrument, but all such counterparts together shall constitute but one agreement. This Agreement shall become effective when each party hereto shall have received a counterpart hereof signed by the other party hereto.

 

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Section 13. Confidentiality.

Wexford agrees to maintain the confidentiality of the Confidential Information (as defined below), except that Wexford may disclose Confidential Information (a) to its partners, members, directors, officers, employees and advisors (and those of its Affiliates), including accountants, legal counsel and other advisors (it being understood that the person to whom such disclosure is made will be informed of the confidential nature of such Confidential Information and instructed to keep such Confidential Information confidential), (b) to the extent required by any subpoena or similar legal process, (c) in connection with the exercise of any remedies hereunder or any suit, action or proceeding relating to this Agreement or the enforcement of rights hereunder, (d) with the consent of the Company, or (e) to the extent such Confidential Information (i) becomes publicly available other than as a result of a breach of this Agreement, or (ii) becomes available to Wexford on a non-confidential basis from a source other than the Company. For the purposes of this Agreement, “Confidential Information” means all non-public information received from the Company relating to the Company or its business, other than any such information that is available to Wexford on a non-confidential basis from a source other than the Company.

Section 14. Further Assurances

The Company and Wexford shall execute such documents and other papers and take such further actions as the other may reasonably request in order to carry out the provisions hereof and provide the services hereunder.

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IN WITNESS WHEREOF, the parties have duly executed this Advisory Services Agreement as of the date first above written.

 

Exhibit 10.18

CONTRIBUTION AGREEMENT

by and between

Gulfport Energy Corporation

and

Diamondback Energy, Inc.

Dated as of

May 7, 2012

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TABLE OF CONTENTS

 

ARTICLE 1 CONTRIBUTION							1
		1.1		Contribution of Permian Assets			1
		1.2		Retained and Assumed Obligations			1
		1.3		Consideration			2
		1.4		Closing Date Adjustment			2
		1.5		Tax Treatment			3
		1.6		Unwind			3
ARTICLE 2 REPRESENTATIONS AND WARRANTIES OF DIAMONDBACK							3
		2.1		Organization of Diamondback			3
		2.2		Power and Authority; Enforceability			4
		2.3		No Violation; Necessary Approvals			4
		2.4		Brokers’ Fees			5
		2.5		Capitalization			5
		2.6		Issuance of Common Stock			5
		2.7		Records			5
		2.8		Diamondback S-1; Financial Statements			6
ARTICLE 3 REPRESENTATIONS AND WARRANTIES OF CONTRIBUTOR							6
		3.1		Organization of Contributor			6
		3.2		Power and Authority; Enforceability			6
		3.3		No Violation; Necessary Approvals			7
		3.4		Title to Permian Assets			7
		3.5		Accredited Investor			7
ARTICLE 4 COVENANTS							8
		4.1		General			8
		4.2		Covenants of Contributor			8
		4.3		Covenants of Diamondback			9
		4.4		Confidentiality			9
		4.5		Notice			10
		4.6		Form S-1			10
		4.7		HSR Filing			11
		4.8		Termination of Certain Agreements			11
		4.9		Access			12
ARTICLE 5 CLOSING							12
		5.1		Conditions Precedent			12
		5.2		Time and Place; Closing			14
		5.3		Contributor’s Closing Deliveries			14
		5.4		Diamondback’s Closing Deliveries			14

 

Gulfport—Diamondback Contribution Agreement

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ARTICLE 6 TERMINATION							15
		6.1		Termination			15
		6.2		Effect of Termination			15
ARTICLE 7 INDEMNIFICATION							15
		7.1		Indemnification			15
		7.2		Indemnification Claim Procedures			16
ARTICLE 8 MISCELLANEOUS							17
		8.1		Definitions			17
		8.2		Entire Agreement			21
		8.3		Assignment; Binding Effect			21
		8.4		Notices			21
		8.5		Specific Performance; Remedies			21
		8.6		Headings			22
		8.7		Governing Law			22
		8.8		Amendment; Extensions; Waivers			22
		8.9		Severability			22
		8.10		Expenses			22
		8.11		Counterparts; Effectiveness			23
		8.12		Construction			23

Schedules

Schedule 2.5—Outstanding Equity Rights

Exhibits

Exhibit A – Form of Promissory Note

Exhibit B – Form of Assignment

Exhibit C – Form of Investor Rights Agreement

 

Gulfport—Diamondback Contribution Agreement

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CONTRIBUTION AGREEMENT

This Contribution Agreement (this “Agreement”), dated as of May 7, 2012 (the “Effective Date”), is by and between Gulfport Energy Corporation, a Delaware corporation (“Contributor”), and Diamondback Energy, Inc., a Delaware corporation (“Diamondback”). Contributor and Diamondback are hereinafter sometimes referred to individually as a “Party” and together as the “Parties”.

RECITALS

A. Contributor owns certain oil, gas and mineral interests in the Permian Basin in West Texas and related assets and contracts (the “Permian Assets”).

B. Contributor desires to contribute the Permian Assets to Diamondback for shares of common stock, par value $0.01 per share, of Diamondback (the “Common Stock”) and other consideration upon the terms and conditions hereinafter set forth.

AGREEMENT

NOW, THEREFORE, in consideration of the premises, the respective representations, warranties, covenants and agreements contained in this Agreement, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, the Parties agree as follows:

ARTICLE 1

CONTRIBUTION

1.1 Contribution of Permian Assets. At the Closing and subject to the terms and conditions contained in this Agreement, Contributor shall contribute, transfer, assign, convey and deliver to Diamondback (or a wholly-owned Subsidiary of Diamondback as directed by Diamondback), and Diamondback (or such Subsidiary) shall acquire and accept, all of Contributor’s right, title and interest held in the Permian Assets. The Parties shall work together to prepare a mutually agreeable schedule of the Permian Assets as soon as practicable after the Effective Date.

1.2 Retained and Assumed Obligations. Upon the Closing, Diamondback shall assume and agree to fulfill, perform, pay and discharge all duties, obligations, claims and liabilities of every kind and character with respect to the Permian Assets or ownership or operation thereof attributable to periods after the Closing Date, including without limitation, (a) those incurred in the ordinary course of business or otherwise, (b) ad valorem, property, severance and other similar taxes or assessments based upon or measured by the ownership of the Permian Assets or the production therefrom, and (c) those related to the condition of the Permian Assets, including, without limitation, obligations to properly plug and abandon or re-plug or re-abandon or remove wells, flowlines, gathering lines and other facilities, equipment or other personal property or fixtures comprising part of the Permian Assets, obligations to restore the surface of the Permian Assets, obligations to bring the Permian Assets into compliance with applicable Laws and liabilities related to any of the foregoing, other than duties, obligations and

 

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liabilities of the Contributor arising under a JOA and billed or billable prior to the Closing Date (the “Assumed Obligations”); provided, however, that upon the Closing, the Contributor shall retain all of Contributor’s duties, obligations, claims and liabilities of every kind and character with respect to the Permian Assets or ownership or operation thereof attributable to periods prior to the Closing Date, including without limitation (i) those incurred in the ordinary course of business or otherwise; and (ii) ad valorem, property, severance and other similar taxes or assessments based upon or measured by the ownership of the Permian Assets or the production therefrom except to the extent specified in clause (c) above.

1.3 Consideration. At the Closing, Diamondback shall, in exchange for the transfer of the Permian Assets, issue to Contributor the following (the “Closing Consideration”):

(i) (a) that number of shares of Common Stock such that Contributor holds thirty-five percent (35%), of the number of shares of Common Stock outstanding immediately prior to the closing of the IPO after giving effect to the issuance of shares of Common Stock in connection with the Gulfport Contribution and the Wexford Contribution. The remaining shares of Common Stock outstanding immediately prior to the closing of the IPO and after giving effect to the Wexford Contribution and the Gulfport Contribution will be held by DB Holdings. No fractional shares of Common Stock shall be issued to Contributor pursuant to this Agreement; and

(ii) (b) a promissory note in the principal amount of $63,590,050.00 substantially in the form attached hereto as Exhibit A (the “Promissory Note”).

1.4 Closing Date Adjustment. Following the Closing, the Closing Consideration shall be reduced or increased in accordance with this Section 1.4 by an amount equal to the difference between the Initial Capital Amount and the Final Capital Amount, divided by sixty-five percent (65%), and then multiplied by thirty-five percent (35%) (the “Capital Adjustment Amount”). For purposes of this Agreement, “Final Capital Amount” shall mean Windsor’s (a) total current assets, consisting of cash, trade accounts receivable (net of an appropriate allowance for doubtful accounts), inventory, prepaid expenses, other current assets, and other assets, less (b) total current liabilities, consisting of trade accounts payable, accounts payable to related parties, accrued capital and other expenses, long-term debt and asset retirement obligations, in each case as of the Closing Date determined in accordance with GAAP, consistently applied. As soon as practicable after the Closing, but in no event later than sixty (60) days after Closing, Diamondback will cause to be prepared and delivered to the Contributor the final settlement statement (the “Final Settlement Statement”) setting forth Windsor’s calculation of the Final Capital Amount on the Closing Date, which Final Settlement Statement shall identify with specificity each component thereof and be prepared in a manner consistent with the preparation of the Initial Capital Amount. As soon as practicable after receipt of the Final Settlement Statement but in no event later than thirty (30) days after receipt of such statement and the supporting documentation with respect thereto as may be requested by the Contributor, the Contributor shall deliver to Diamondback a written report containing any changes that the Contributor proposes to make to the Final Settlement Statement. The Contributor’s failure to deliver to Diamondback a written report detailing proposed changes to the Final Settlement Statement by that date shall be deemed an acceptance by the Contributor of the Final Settlement

 

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Statement as submitted by Diamondback. The Parties shall agree with respect to the changes proposed by the Contributor, if any, no later than sixty (60) days after receipt of Diamondback’s proposed Final Settlement Statement. If Diamondback disputes the Contributor’s exceptions, then Diamondback and the Contributor will negotiate in good faith to resolve such dispute. If Diamondback and the Contributor are unable to resolve the dispute within thirty (30) days after the date of the Contributor’s dispute notice, then the dispute shall be submitted to a mutually agreed upon arbitrator (the “Arbitrator”) for resolution and the Arbitrator’s decision shall be final and binding on the Parties and there shall be no right of appeal therefrom. The costs of the Arbitrator shall be paid by Diamondback and the Contributor proportionate to the success of the claims made. No later than five (5) days after reaching such agreement, the Capital Adjustment Amount shall be paid, if positive, by Diamondback to the Contributor, and if negative, by the Contributor to Diamondback by wire transfer in immediately available funds.

1.5 Tax Treatment.

(a) The Parties intend for the transactions between them contemplated in this Agreement to qualify as a tax-free exchange under Section 351 of the Code and in accordance therewith, the Parties acknowledge that Contributor and DB Holdings together will own one-hundred percent (100%) of all of the issued and outstanding capital stock of Diamondback immediately following the consummation of the Gulfport Contribution and the Wexford Contribution and immediately prior to the consummation of the IPO.

(b) Contributor and Diamondback hereby agree to the U.S. federal income tax treatment described in this Section 1.5, and neither Contributor nor Diamondback shall maintain a position on their respective U.S. federal income tax returns or otherwise that is inconsistent therewith.

1.6 Unwind. If the Gulfport Contribution is made but the IPO does not close for any reason, the Permian Assets shall be returned to Contributor and Contributor shall return the Closing Consideration and this Agreement shall be null and void.

ARTICLE 2

REPRESENTATIONS AND WARRANTIES OF DIAMONDBACK

Diamondback hereby represents and warrants to Contributor as of the Effective Date and as of the Closing Date (except to the extent that any such representation or warranty expressly relates to another date, in which case such representation or warranty shall be as of such date) as follows:

2.1 Organization of Diamondback. Diamondback (a) is a corporation duly organized, validly existing and in good standing under the Laws (as defined below) of the State of Delaware, (b) is duly qualified to do business as a foreign corporation and is in good standing under the Laws of each jurisdiction in which either the ownership or use of the properties owned or used by it, or the nature of the activities conducted by it, requires such qualification, (c) has the corporate power and authority necessary to own or lease its properties and to carry on its business as currently conducted and (d) is not in breach or violation of, or default under, any

 

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provision of its Organizational Documents. Diamondback has not approved or taken any action, and there is not pending or (to Diamondback’s knowledge) threatened any action, suit, arbitration, mediation, investigation or similar proceeding (an “Action”) for the dissolution, liquidation, insolvency or rehabilitation of Diamondback.

2.2 Power and Authority; Enforceability. Diamondback has the relevant corporate power and authority necessary to execute and deliver this Agreement and each such other document contemplated hereby and any amendments or supplements to any of the foregoing (collectively, the “Transaction Documents”) to which Diamondback is a party, and to perform and consummate the transactions contemplated by the Gulfport Contribution (the “Transactions”). Diamondback has taken all action necessary to authorize the execution and delivery by Diamondback of each Transaction Document to which it is a party, the performance of Diamondback’s obligations thereunder, and the consummation by Diamondback of the Transactions, the Wexford Contribution and the IPO (subject to final authorization of the Pricing Committee of the Board of Directors of Diamondback). Each Transaction Document to which Diamondback is a party has been duly authorized, executed and delivered by Diamondback, and constitutes the legal, valid and binding obligation of Diamondback, enforceable against Diamondback in accordance with its terms except as such enforceability may be subject to the effects of bankruptcy, insolvency, reorganization, moratorium or other Laws relating to or affecting the rights of creditors and general principles of equity (the “Enforceability Exception”).

2.3 No Violation; Necessary Approvals. The execution and the delivery by Diamondback of this Agreement and the other Transaction Documents to which it is a party, the performance by Diamondback of its obligations hereunder and thereunder, and consummation of the Transactions, the Wexford Contribution and the IPO by Diamondback will not (i) with or without notice or lapse of time, constitute, create or result in a breach or violation of, default under, loss of benefit or right under or acceleration of performance of any obligation required under any (A) law (statutory, common or otherwise), constitution, ordinance, rule, regulation, executive order or other similar authority (“Law”) enacted, adopted, promulgated or applied by any legislature, agency, bureau, branch, department, division, commission, court, tribunal or other similar recognized organization or body of any federal, state, county, municipal, local or foreign government or other similar recognized organization or body exercising similar powers or authority (a “Governmental Body”), (B) order, ruling, decision, award, judgment, injunction or other similar determination or finding by, before or under the supervision of any Governmental Body or arbitrator (an “Order”), (C) contract, agreement, arrangement, commitment, instrument, document or similar understanding (whether written or oral), including a lease, sublease and rights thereunder (“Contract”) or permit, license, certificate, waiver, notice and similar authorization (“Permit”) to which, in the case of (A), (B) or (C), Diamondback is a party or by which Diamondback is bound or any of its assets are subject, or (D) any provision of the Organizational Documents of Diamondback as in effect on the Closing Date; (ii) result in the imposition of any Lien upon any assets owned by Diamondback, or any shares of Common Stock owned by any of the stockholders of Diamondback; (iii) require any Consent under any Contract or Organizational Document to which Diamondback is a party or by which it is bound or any of its assets are subject, except for any such Consents as have been obtained; (iv) require any Permit under any Law or Order other than (A) required filings, if any, with the Commission

 

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and (B) notifications or other filings with state or federal regulatory agencies after the Closing that are necessary or convenient and do not require approval of the agency as a condition to the validity of the Transactions, the Wexford Contribution or the IPO; or (v) trigger any rights of first refusal, preferential purchase or similar rights with respect to any equity interest in Diamondback, which have not been validly waived.

2.4 Brokers’ Fees. Diamondback has no liability or obligation to pay any compensation to any broker, finder or agent with respect to the Transactions, the Wexford Contribution or the IPO for which Contributor could become directly or indirectly liable, other than any underwriter discounts incurred in connection with any sale of shares of Common Stock by Contributor.

2.5 Capitalization. As of the Effective Date, the authorized capital stock of Diamondback consists of 100 shares of common stock, of which, 100 shares were issued and outstanding. All of the issued and outstanding equity interests in Diamondback: (a) have been duly authorized and are validly issued, fully paid and nonassessable; (b) were issued in compliance with all applicable state and federal securities Laws; and (c) were not issued in breach or violation of, or did not cause as a result of the issuance thereof a default under, any Contract with or right granted to any other person. Except as set forth on Schedule 2.5, Diamondback has no outstanding options, warrants, exchangeable or convertible securities, subscription rights, exchange rights, statutory pre-emptive rights, preemptive rights granted under its Organizational Documents, stock appreciation rights, phantom stock, profit participation or similar rights, or any other right or instrument pursuant to which any person may be entitled to purchase any security interests in Diamondback, and has no obligation to issue any rights or instruments (“Equity Rights”). There are no Contracts with respect to the voting or transfer of any of the equity interest in Diamondback. Diamondback is not obligated to redeem or otherwise acquire any of its outstanding shares of Common Stock or other equity interests. Diamondback does not, directly or indirectly, control, own or have any Equity Interest in any Person.

2.6 Issuance of Common Stock. The shares of Common Stock, when issued and delivered in accordance with the terms of this Agreement for the consideration described in this Agreement, will have been (i) duly authorized by Diamondback and when issued against the consideration therefor, will be validly issued by Diamondback, (ii) fully paid and non-assessable, (iii) not subject to any preemptive or similar rights created by any Law or Order to which Diamondback is a party or by which it is bound and (iv) free and clear of all Liens, other than those created by Contributor, including but not limited to those, if any, in favor of its lenders under the Loan Documents, arising from the Underwriting Agreement and arising under U.S. securities Laws.

2.7 Records. The copies of the Organizational Documents of Diamondback that were provided to Contributor are accurate and complete and reflect all amendments made through the date hereof. Except as set forth in the S-1, no steps have been taken by Diamondback or its officers, directors, or stockholder to effect or authorize any further amendment or modification thereto. The minute books of Diamondback and the other records made available to Contributor for review were correct and complete as of the date of such

 

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review, no further entries have been made through the Effective Date, such minute books and records contain the true signatures of the persons purporting to have signed them, and such minute books and records contain an accurate record of all actions of the members, managers or any other governing body of each Diamondback taken by written consent, at a meeting, or otherwise since formation.

2.8 Diamondback S-1; Financial Statements. Diamondback has filed with the Securities and Exchange Commission (the “Commission”) a Registration Statement on Form S-1, File No. 333-179502 (the “S-1”). The consolidated financial statements of Windsor included in the S-1 comply as to form in all material respects with applicable accounting requirements and with the published rules and regulations of the Commission with respect thereto and fairly present, in conformity in all material respects with generally accepted accounting principles (“GAAP”) applied on a consistent basis (except as may be indicated in the notes thereto), the consolidated financial position of Windsor and its consolidated subsidiaries as of the dates thereof and their consolidated results of operations and changes in financial position for the periods then ended.

ARTICLE 3

REPRESENTATIONS AND WARRANTIES OF CONTRIBUTOR

Contributor hereby represents and warrants to Diamondback as of the Effective Date and as of the Closing Date (except to the extent that any such representation or warranty expressly relates to another date, in which case such representation or warranty shall be as of such date) as follows:

3.1 Organization of Contributor. Contributor (a) is a corporation duly organized, validly existing and in good standing under the Laws of the State of Delaware, (b) is duly qualified to do business as a foreign corporation and is in good standing under the Laws of the State of Texas, (c) has the corporate power and authority necessary to own or lease its properties and to carry on its business as currently conducted and (d) is not in breach or violation of, or default under, any provision of its Organizational Documents. Contributor has not approved or taken any action, and there is not pending or (to Contributor’s knowledge) threatened Action for the dissolution, liquidation, insolvency or rehabilitation of Contributor.

3.2 Power and Authority; Enforceability. Contributor has the relevant corporate power and authority necessary to execute and deliver each Transaction Document to which it is a party and to perform and consummate the Transactions. Contributor has taken all action necessary to authorize its execution and delivery by Contributor of each Transaction Document to which Contributor is a party, the performance of its obligations thereunder and the consummation by Contributor of the Transactions. Each Transaction Document to which Contributor is a party has been duly authorized, executed and delivered by Contributor, and constitutes the legal, valid and binding obligation of Contributor, enforceable against Contributor in accordance with its terms, subject to the Enforceability Exception.

 

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3.3 No Violation; Necessary Approvals. The execution and the delivery by Contributor of this Agreement and the other Transaction Documents to which Contributor is a party, the performance by Contributor of its obligations hereunder and thereunder and the consummation of the Transactions by Contributor will not (i) with or without notice or lapse of time, constitute, create or result in a breach or violation of, default under, loss of benefit or right under or acceleration of performance of any obligation required under any Law, Order, Contract or Permit to which Contributor is a party or by which it is bound or any of its assets is subject, or any provision of Contributor’s Organizational Documents as in effect on the Closing Date; (ii) result in the imposition of any Lien upon any assets owned by Contributor, including without limitation the Permian Assets; (iii) require any Consent under any Contract or organizational document to which Contributor is a party or by which it is bound, other than such Consents that have been obtained and the Consent of the lenders under the Loan Documents; or (iv) require any Permit under any Law or Order other than (A) required filings, if any, with the Commission and (B) notifications or other filings with state or federal regulatory agencies after the Closing that are necessary or convenient and do not require approval of the agency as a condition to the validity of the Transactions.

3.4 Title to Permian Assets. Contributor warrants and shall forever defend the title to the Permian Assets unto Diamondback against every Person whomsoever lawfully claiming or to claim the same or any part thereof by, through, or under Contributor, but not otherwise, subject, however, to the Permitted Liens (regardless of whether they are released on or prior to Closing pursuant to Article 5) and to any other Liens created, imposed, modified, amended or extended under or pursuant to the Loan Documents which will be released on or prior to Closing pursuant to Article 5; it being the intent (without modifying, amending or expanding the scope of the preceding warranty of title) that, as of Closing pursuant to Article 5, the Permian Assets will not be encumbered by Liens or other defects in title to which the Permian Assets were not encumbered as of the time the Permian Assets were originally assigned and conveyed to Contributor, save and except for the Permitted Liens (regardless of whether they are released on or prior to Closing pursuant to Article 5) and any other Liens created, imposed, modified, amended or extended under or pursuant to the Loan Documents which will be released on or prior to Closing pursuant to Article 5. Contributor further warrants that any conveyance of the Permian Assets at Closing pursuant to Section 5.3(a) also conveys, assigns and transfers to Diamondback, its successors and assigns, as of Closing, all warranties, claims and causes of action of whatsoever type or character, in contract or in tort, that Contributor now has or may hereafter acquire from its predecessors-in-title to the Permian Assets, with respect to title to the Permian Assets. Except for the limited warranty expressed in the preceding sentence(s) of this Section 3.4, no warranty or representation, express, implied, statutory, or otherwise, with respect to Contributor’s title to any of the Permian Assets is provided in this Agreement or shall be contained in the instruments of conveyance and assignment to be delivered by Contributor to Diamondback on the Closing Date pursuant to Section 5.3(a).

3.5 Accredited Investor. Contributor is an “accredited investor,” as such term is defined in Regulation D of the Securities Act, and will acquire the Common Stock for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws. Contributor acknowledges that the Common Stock will not be registered under the Securities Act or any applicable state securities law, and that the Common Stock may not be transferred or sold except pursuant to the registration provisions of the Securities Act or pursuant to an applicable exemption therefrom and pursuant to state securities laws and regulations as applicable.

 

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ARTICLE 4

COVENANTS

4.1 General.

(a) Subject to the terms and conditions provided in this Agreement, each Party covenants and agrees to use commercially reasonable efforts and cooperate with each other in (a) promptly determining whether any filings are required to be made or consents, approvals, waivers, permits or authorizations are required to be obtained (under any applicable Laws or from any Governmental Body or third party) in connection with the Transactions, (b) promptly making any such filings, furnishing information required in connection therewith and timely seeking to obtain any such consents, approvals, waivers, permits or authorizations and (c) taking all actions and doing, or causing to be done, all things necessary, proper and/or appropriate to consummate and make effective the Transactions.

(b) If any time after the Closing any further action is necessary or desirable to carry out this Agreement’s purposes, each Party will take such further action (including executing and delivering any further instruments and documents, obtaining any Permits and Consents and providing any reasonably requested information) as any other Party may reasonably request, all at the requesting Party’s sole cost and expense (unless the requesting Party is entitled to indemnification therefor under Article 7).

4.2 Covenants of Contributor. From the Effective Date through the Closing, and except in the ordinary course of business, as contemplated by the AMIA, JOAs or the JDA and as contemplated by or specified in this Agreement or the Transactions, the Contributor will not, without the prior written consent of Diamondback:

(a) sell, transfer (or agree to sell or transfer) or otherwise dispose of, or cause the sale, transfer or disposition of (or agree to do any of the foregoing) all or any portion of the Permian Assets;

(b) pledge, hypothecate or encumber all or any portion of the Permian Assets; or

(c) cause or take any action that would render any of the representations or warranties set forth in Article 3 untrue in any material respect.

(d) Notwithstanding anything in this Agreement to the contrary, Contributor shall be permitted to (i) participate in negotiations or discussions with any person or group of persons other than Diamondback and its affiliates that has made (and not withdrawn) an unsolicited offer, indication of interest, proposal or inquiry relating to an alternative transaction that the Special Committee believes in good faith would reasonably be expected to result in a transaction more favorable to the stockholders of

 

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Contributor than the Transactions, (ii) thereafter furnish to such third party non-public information relating to the Permian Assets and afford access to the Permian Assets to such third party, in all cases for the purpose of assisting with or facilitating an alternative transaction, and (iii) after the termination of this Agreement pursuant to Section 6.1 enter into an alternative transaction or any agreement, arrangement or understanding, including, without limitation, any letter of intent, term sheet or other similar document, relating to an alternative transaction with such third party.

4.3 Covenants of Diamondback. From the Effective Date through the Closing, and except as contemplated by or specified in this Agreement, the Transactions, the IPO or the S-1, Diamondback will not, without the prior written consent of the Contributor:

(a) amend its Organizational Documents;

(b) authorize for issuance, issue, sell, deliver or agree or commit to issue, sell or deliver (whether through the issuance or granting of options, warrants, commitments, subscriptions, rights to purchase or otherwise) any stock of any class or any other debt or equity securities or equity equivalents (including any stock options or stock appreciation rights);

(c) split, combine or reclassify any shares of its capital stock, declare, set aside or pay any dividend or other distribution (whether in cash, stock or property or any combination thereof) in respect of its capital stock, make any other actual, constructive or deemed distribution in respect of its capital stock or otherwise make any payments to stockholders in their capacity as such, or redeem or otherwise acquire any of its securities or any securities of any of its subsidiaries;

(d) sell, lease, license, transfer, distribute or otherwise dispose of any material assets in any single transaction or series of related transactions or permit or cause Windsor to do so;

(e) except as may be required as a result of a change in law or in GAAP, materially change any of the accounting principles, practices or methods used by it; or

(f) cause or take any action that would render any of the representations and warranties set forth in Article 2 untrue in any material respect.

4.4 Confidentiality. Each Party will, and will cause each of its respective Affiliates, directors, officers, employees, agents, representatives and similarly situated persons to treat and hold as confidential, and not use or disclose, all of the information possessed by such person concerning the Transactions, the Wexford Contribution, the IPO, Diamondback, its business, the negotiation or existence and terms of this Agreement and the business affairs of Contributor, except for disclosures (i) to the person’s professional advisors, the actions for which the disclosing person will be responsible, (ii) required for such person to perform obligations it may have under this Agreement, or (iii) required by applicable Law or securities exchange regulations.

 

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4.5 Notice. From the Effective Date through the Closing, each Party shall give prompt written notice to the other Party of (i) any representation or warranty made by it contained in this Agreement that is qualified as to materiality becoming untrue or inaccurate in any respect or any such representation or warranty that is not so qualified becoming untrue or inaccurate in any material respect, or (ii) the failure by it to comply with or satisfy in any material respect any covenant, condition or agreement to be complied with or satisfied by it under this Agreement; provided, however, that no such notification shall affect the representations, warranties, covenants or agreements of the Parties or the conditions to the obligations of the Parties under this Agreement.

4.6 Form S-1.

(a) Diamondback shall prepare an amendment to the S-1 and Contributor shall prepare a Current Report on Form 8-K, each of which shall include descriptions of this Agreement and the Transactions and such forms shall be filed simultaneously with the Commission. The Parties shall cooperate and consult with each other with respect to the disclosure of the Transactions contained in the Form 8-K and the S-1. Diamondback shall promptly provide copies or all written comments received from the Commission, and consult with Contributor with respect to any comments received from the Commission regarding the Transaction, and make available to Contributor upon its request a complete and correct copy of any amendments that are filed with the Commission. At its effective time, the S-1 shall comply as to form in all material respects with the rules and regulations promulgated by the Commission under the Securities Act and shall not contain any untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary in order to make the statements therein in light of the circumstances under which they were made not misleading. Diamondback will advise Contributor, after it receives notice thereof, of the time when S-1 has become effective or any supplement or amendment has been filed, or the issuance of any stop order.

(b) Diamondback shall use its commercially reasonable efforts to include the shares of Common Stock of Contributor requested by Contributor to be included in the S-1 as a selling stockholder and such shares of Common Stock shall be included in the underwriting on the same terms and conditions as the shares of Common Stock being offered by Diamondback. If the managing underwriters advise Diamondback that in their good faith judgment the number of shares of Common Stock requested to be included in the S-1 by Contributor and DB Holdings exceeds the number which can be sold in the IPO without materially and adversely affecting the marketability of the IPO, then the S-1 shall include the maximum number of shares that the managing underwriters advise can be sold in the IPO by Contributor and DB Holdings allocated as follows: (i) first, the shares of Common Stock that Diamondback proposes to sell, and (ii) second, to the extent that any other shares of Common Stock may be included without exceeding the limitations recommended by the underwriters as aforesaid, shares of Common Stock to be included in the S-1 by Contributor and DB Holdings will be included on a pro rata basis (or in such other proportion mutually agreed between Contributor and DB Holdings), based on the number shares of Common Stock held by Contributor and DB Holdings.

 

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4.7 HSR Filing. Each of the Contributor and Diamondback shall, to the extent required, file or cause to be filed any Notification and Report Forms and related material with the Federal Trade Commission and the Antitrust Division of the United States Department of Justice under the HSR Act within five Business Days following the Effective Date. Each of the Parties will use commercially reasonable efforts to obtain a waiver of the applicable waiting period with respect to the HSR Act and will promptly make any further filings pursuant thereto that may be necessary, proper or advisable in connection therewith. The Parties will cooperate with each other in connection with the making of all such filings or responses, including providing copies of all such documents to the non-filing or non-responding Party and its advisors prior to filing or responding to allow such other Party reasonable time to review and comment on such filings or responses. The filing fees for all such filings after the Effective Date will be paid by Diamondback. Any other fees or expenses that arise in connection with the making of all such filings or responses with respect to the HSR Act will be paid by the Person that incurs such fees or expenses.

4.8 Termination of Certain Agreements.

(a) The Parties shall cause the AMIA, JOAs and JDA (the “Terminated Agreements”) to be terminated effective as of the Closing Date; provided, such termination shall not affect the obligations of Contributor or the rights of the Windsor Entity counterparty against Contributor under the Terminated Agreements attributable to the period prior to the Closing Date; and provided, further that Contributor hereby waives any and all requirements of Windsor under the AMIA to have assigned any portion of any oil, gas and mineral lease, working interest, leasehold interest or other oil and gas interest thereunder to Contributor.

(b) For the avoidance of doubt, such termination of the Terminated Agreements (i) shall not affect the Contributor’s right to receive production revenues attributable to its ownership of the Permian Assets during the period prior to the Closing Date, and (ii) shall not relieve Contributor of (x) any obligation for the payment of money or for indemnity under any Terminated Agreement for the period prior to the Closing Date, or (y) the obligation to convey any oil, gas and mineral lease, working interest, leasehold interest or other oil and gas interest covered by the AMIA acquired by Contributor, an Affiliate of Contributor, or an agent or representative of Contributor or any such Affiliate, or which Contributor, Affiliate or agent or representative had the right to acquire prior to the Closing Date.

(c) For the avoidance of doubt, such termination of the Terminated Agreement (i) shall not affect the Windsor Entity counterparty’s right to receive production revenues attributable to its ownership of oil and gas interests during the period prior to the Closing Date, and (ii) shall not relieve the Windsor Entity counterparty of any obligation for the payment of money or for indemnity under any Terminated Agreement for the period prior to the Closing Date.

 

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(d) All of the rights corresponding to the obligations of Contributor under clause (b) above shall be assigned by the Windsor Entity counterparty to Diamondback, or if applicable, its permitted assigns pursuant to Section 5.3(a) of this Agreement.

4.9 Access. Diamondback will cause or permit representatives of Contributor to have full access at all reasonable times, and in a manner so as not to interfere with the normal business operations of Diamondback, to all premises, properties, personnel, books, records, Contracts, and documents pertaining to the Wexford Contribution, the IPO, the Transactions and such other information to enable Contributor to determine the satisfaction of the conditions to closing set forth in Section 5.1 and will furnish copies of all such books, records, Contracts, and documents and all financial, operating and other data, and other information as Contributor may reasonably request; provided, however, that no investigation pursuant to this Section 4.9 will affect any representations or warranties made herein or the conditions to the Parties’ obligations to consummate the Transactions.

ARTICLE 5

CLOSING

5.1 Conditions Precedent.

(a) Conditions to Each Party’s Obligations. The obligations of each Party to effect the Transactions shall be subject to the satisfaction or waiver of the following conditions:

(i) No Law or Order shall have been enacted, issued, entered, promulgated or enforced by any Governmental Body that prohibits the consummation of the Transactions, the Wexford Contribution or the IPO (which condition may not be waived by any Party), nor shall any proceeding brought by a Governmental Body of competent jurisdiction be pending that seeks the foregoing;

(ii) The Commission shall have advised Diamondback that it has no further comments on the S-1 and each Party shall be satisfied that the offering will be completed;

(iii) Any applicable waiting period under the HSR Act relating to the Transactions and the Wexford Contribution shall have expired or been terminated; and

(iv) Any other governmental or regulatory notices, approvals or other requirements necessary to consummate the Transactions, the Wexford Contribution and the IPO shall have been given, obtained or complied with, as applicable.

 

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(b) Conditions to Obligations of Diamondback. The obligations of Diamondback to consummate the transactions to be performed by it in connection with the Closing is subject to satisfaction (or waiver by it in writing) of the following conditions:

(i) The representations and warranties of the Contributor contained in this Agreement shall be true and correct in all material respects at the Closing Date as if made at that time (except to the extent that any representation or warranty speaks as of an earlier date, in which case it must be true and correct only as of that earlier date);

(ii) Contributor shall have performed in all material respects all agreements and covenants required by this Agreement to be performed or complied with by it on or prior to the Closing Date;

(iii) Contributor shall have delivered to Diamondback written evidence of the termination of each of the Terminated Agreements;

(iv) Contributor shall have executed and delivered to Diamondback the documents required to be delivered by it pursuant to Section 5.3 hereof; and

(v) All Liens on the Permian Assets created by the Loan Documents shall have been released by the lenders thereunder.

Any or all of the foregoing conditions may be waived by Diamondback in its sole and absolute discretion.

(c) Conditions to Obligations of the Contributor. The obligations of the Contributor to consummate the transactions to be performed by it in connection with the Closing is subject to satisfaction (or waiver by it in writing) of the following conditions:

(i) The representations and warranties of Diamondback contained in this Agreement shall be true and correct in all material respects at the Closing Date as if made again at that time (except to the extent that any representation or warranty speaks as of an earlier date, in which case it must be true and correct only as of that earlier date);

(ii) Diamondback shall have performed in all material respects all agreements and covenants required by this Agreement to be performed or complied with by it on or prior to the Closing Date;

(iii) Contributor shall have determined that the terms and conditions of the Wexford Contribution, including, without limitation, matters relating to title to the assets held by Windsor, and the IPO, including, without limitation, the IPO Price and the net proceeds of the IPO, are acceptable to Contributor in its sole and absolute discretion (as determined by the Special Committee);

 

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(iv) The Common Stock shall have been approved for listing on The NASDAQ Global Market or another national securities exchange, subject only to official notice of issuance;

(v) The Wexford Contribution shall have occurred;

(vi) Diamondback shall have delivered to Contributor written evidence of the termination of each of the Terminated Agreements; and

(vii) Diamondback shall have executed and delivered to the Contributor the documents required to be delivered pursuant to Section 5.4 hereof.

5.2 Time and Place; Closing. Unless this Agreement shall have terminated pursuant to Article 6, the closing of the Transactions (the “Closing”) shall occur upon the satisfaction or waiver of the conditions in Section 5.1 (the “Closing Date”). The Closing shall take place at a place as determined by Contributor and Diamondback.

5.3 Contributor’s Closing Deliveries. On the Closing Date, Contributor shall deliver or cause to be delivered to Diamondback the following closing documents:

(a) Instruments of conveyance and assignment, substantially in the form attached hereto as Exhibit B (the “Assignments”) and any other documents that are in the possession of Contributor which are reasonably requested by Diamondback and are reasonably necessary or desirable to assign, transfer, convey, contribute and deliver the Permian Assets to Diamondback (or, as instructed in writing by Diamondback, a wholly-owned subsidiary of Diamondback) and effectuate the transactions contemplated hereby;

(b) A certification regarding the accuracy in all material respects of Contributor’s representations and warranties in this Agreement at the Closing Date (except to the extent that any representation or warranty speaks as of an earlier date, in which case it must be true and correct only as of that earlier date); and

(c) The Investor Rights Agreement, substantially in the form attached hereto as Exhibit C (the “Investor Rights Agreement”) duly executed and delivered by the Contributor.

5.4 Diamondback’s Closing Deliveries. On the Closing Date, Diamondback shall deliver or cause to be delivered to the Contributor the following closing documents:

(a) Diamondback shall have issued shares of the Common Stock to Contributor either in the form of one or more certificates, in such names as Contributor shall direct or through the electronic registration of such Common Stock with the Depository Trust Company, a New York corporation;

(b) A certification regarding the accuracy in all material respects of each of their respective representations and warranties in this Agreement at the Closing Date (except to the extent that any representation or warranty speaks as of an earlier date, in which case it must be true and correct only as of that earlier date); and

 

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(c) The Investor Rights Agreement duly executed and delivered by Diamondback.

(d) The Promissory Note duly executed and delivered by Diamondback.

ARTICLE 6

TERMINATION

6.1 Termination. This Agreement may be terminated as follows:

(a) by mutual written consent of the Parties;

(b) by either Party if any court of competent jurisdiction in the United States or other United States federal or state Governmental Body shall have issued a final Order or taken any other final action, restraining, enjoining or otherwise prohibiting the Transactions, the Gulfport Contribution, the Wexford Contribution or the IPO and such order, decree, ruling or other action is or shall have become nonappealable;

(c) by Diamondback, upon a breach of any representation, warranty, covenant or agreement on the part of the Contributor set forth in this Agreement such that the conditions set forth in Section 5.1(a) and (b) shall have become incapable of fulfillment and such breach shall not have been waived by Diamondback;

(d) by Contributor, upon a breach of any representation, warranty, covenant or agreement on the part of Diamondback set forth in this Agreement such that the conditions set forth in Section 5.1(a) and (c) shall have become incapable of fulfillment and such breach shall not have been waived by Contributor; or

(e) by either Party if the Closing does not occur by July 31, 2012, or at such earlier time as Diamondback determines not to proceed with or otherwise terminates the IPO.

6.2 Effect of Termination. In the event of the termination and abandonment of this Agreement pursuant to Section 6.1, this Agreement shall forthwith become void and have no effect without any liability on the part of any party hereto or its Affiliates, directors, officers or stockholders other than the provisions of this Section 6.2 and Article 7 hereof. Nothing contained in this Section 6.2 shall relieve any party from liability for any breach of this Agreement prior to such termination.

ARTICLE 7

INDEMNIFICATION

7.1 Indemnification.

(a) Contributor shall indemnify and hold Diamondback and its Affiliates, and their respective officers, directors, managers, employees, agents, representatives, controlling persons, members, stockholders and similarly situated persons, harmless from

 

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and pay any and all Damages directly or indirectly, resulting from, relating to, arising out of or attributable to (i) any breach of any representation or warranty the Contributor has made in this Agreement; or (ii) any breach, violation or default by Contributor of any covenant, agreement or obligation of Contributor in this Agreement. “Damages” means all losses (including diminution in value), damages and other costs and expenses of any kind or nature whatsoever, whether known or unknown, contingent or vested, matured or unmatured, and whether or not resulting from third-party claims, including costs (including reasonable fees and expenses of attorneys, other professional advisors and expert witnesses and the allocable portion of the relevant person’s internal costs) of investigation, preparation and litigation in connection with any Action or threatened Action.

(b) Diamondback shall indemnify and hold the Contributor and its Affiliates, and their respective officers, directors, managers, employees, agents, representatives, controlling persons, members, stockholders and similarly situated persons, harmless from and pay any and all Damages directly or indirectly, resulting from, relating to, arising out of or attributable to (i) any breach of any representation or warranty Diamondback has made in this Agreement; (ii) any breach, violation or default by Diamondback of any covenant, agreement or obligation of Diamondback in this Agreement; or (iii) the Assumed Obligations.

7.2 Indemnification Claim Procedures.

(a) If any Action is commenced or threatened that may give rise to a claim for indemnification (an “Indemnification Claim”) by any person entitled to indemnification under this Agreement (each, an “Indemnified Party”) against any person obligated to indemnify an Indemnified Party (an “Indemnitor”), then such Indemnified Party will promptly give notice to the Indemnitor. Failure to notify the Indemnitor will not relieve the Indemnitor of any liability that it may have to the Indemnified Party, except to the extent the defense of such Action is materially and irrevocably prejudiced by the Indemnified Party’s failure to give such notice. An Indemnitor may elect at any time to assume and thereafter conduct the defense of the Indemnification Claim with counsel of the Indemnitor’s choice reasonably satisfactory to the Indemnified Party; provided, however, that the Indemnitor will not approve of the entry of any judgment or enter into any settlement with respect to the Indemnification Claim without the Indemnified Party’s prior written approval (which must not be withheld unreasonably). Until an Indemnitor assumes the defense of the Indemnification Claim, the Indemnified Party may defend against the Indemnification Claim in any manner the Indemnified Party reasonably deems appropriate. If the Indemnified Party gives an Indemnitor notice of an Indemnification Claim and the Indemnitor does not, within ten (10) days after such notice is given, give notice to the Indemnified Party of its election to assume the defense of such Indemnification Claim and thereafter promptly assume such defense, then the Indemnitor will be bound by any judicial determination made with respect to such Indemnification Claim or any compromise or settlement of such Indemnification Claim effected by the Indemnified Party.

 

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(b) A claim for any matter not involving a third party may be asserted by notice to the Party from whom indemnification is sought.

ARTICLE 8

MISCELLANEOUS

8.1 Definitions. For the purposes of this Agreement, the following terms have the meanings set forth below.

“Action” has the meaning set forth in Section 2.1.

“Affiliate” means, with respect to any Person, a Person that, directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with the specified Person. For the purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”) as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

“Agreement” has the meaning set forth in the introductory paragraph hereto.

“AMIA” means that certain Area of Mutual Interest Agreement by and between Windsor and Contributor dated November 1, 2007, as amended by that certain First Supplement to Area of Mutual Interest Agreement by and between Windsor and Contributor dated as of March 20, 2008, and that certain Second Supplement to Area of Mutual Interest Agreement by and between Windsor and Contributor dated as of October 31, 2008.

“Arbitrator” has the meaning set forth in Section 1.4.

“Assignments” has the meaning set forth in Section 5.3(a).

“Assumed Obligations” has the meaning set forth in Section 1.2.

“Business Day” means any day that is not a Saturday, Sunday or legal holiday in the State of Oklahoma and the State of Texas.

“Capital Adjustment Amount” has the meaning set forth in Section 1.4.

“Closing” or “Closing Date” has the meaning set forth in Section 5.2.

“Closing Consideration” has the meaning set forth in Section 1.3.

“Commission” has the meaning set forth in Section 2.8.

“Common Stock” has the meaning set forth in the Recitals hereto.

“Consent” means any consent, order, waiver, approval or authorization of, or registration, qualification, designation, declaration or filing with, any Person or Governmental Body or under any applicable Laws.

“Contract” has the meaning set forth in Section 2.3.

 

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“Contributor” has the meaning set forth in the introductory paragraph hereto.

“Damages” has the meaning set forth in Section 7.1(a).

“Diamondback” has the meaning set forth in the introductory paragraph hereto.

“Effective Date” has the meaning set forth in the introductory paragraph hereto.

“Enforceability Exception” has the meaning set forth in Section 2.2.

“Equity Interest” means (a) with respect to a corporation, any and all shares of capital stock and any Equity Rights with respect thereto, (b) with respect to a partnership, limited liability company, trust, or similar Person, any and all units, interests or other partnership/limited liability company interests, and any Equity Rights with respect thereto, and (c) any other direct or indirect equity ownership or participation in a Person.

“Equity Rights” has the meaning set forth in Section 2.5.

“Final Capital Amount” has the meaning set forth in Section 1.4.

“Final Settlement Statement” has the meaning set forth in Section 1.4.

“GAAP” has the meaning set forth in Section 2.8.

“Governmental Body” has the meaning set forth in Section 2.3.

“Gulfport Contribution” means the Contributor’s contributions of the Permian Assets to Diamondback in return for shares of Common Stock pursuant to this Agreement.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“Indebtedness” means, with respect to any Person, as of a specified date, the sum of (i) all indebtedness of such Person, whether or not contingent, whether secured or unsecured, for borrowed money; (ii) all obligations and liabilities of such Person for the deferred purchase price of property or services; (iii) all indebtedness and obligations of such Person evidenced by notes, bonds, debentures, finance leases or other similar instruments and liabilities, whether contingent or not contingent, for reimbursement in respect of any letter of credit, banker’s acceptance or similar credit transaction; (iv) all obligations and liabilities in respect of any lease of (or other arrangements conveying the right to use) real or personal property, or a combination thereof, which liabilities are required to be classified and accounted for under GAAP as capital leases; (v) all obligations and liabilities with respect to hedging, swaps or similar arrangements; and (vi) all guarantees, pledges and grants of a security interest by such Person in respect of or securing obligations with respect to the indebtedness (as referred to in clauses (i) through (v) above) of others.

“Indemnification Claim” has the meaning set forth in Section 7.2(a).

“Indemnified Party” has the meaning set forth in Section 7.2(a).

“Indemnitor” has the meaning set forth in Section 7.2(a).

“Initial Capital Amount” means as of February 29, 2012 the amount of ($118,095,807.00).

 

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“IPO” means the underwritten initial public offering of Diamondback in which it will issue shares of Common Stock pursuant to the S-1.

“IPO Price” means the price per share of Common Stock in the IPO, as set forth on the cover page of the final Prospectus relating to the IPO.

“JDA” means that certain Development Agreement by and between Windsor, Contributor and Windsor Energy Group, L.L.C. dated November 1, 2007, as amended by that certain First Amendment to the Development Agreement dated November 1, 2007 and to each of the Joint Operating Agreements dated as of November 1, 2007 for the East Bloxom, Georgetown, Kelly, Shelley-Michelle, Tori and West Bloxom Prospects by and between Windsor, Contributor and Windsor Energy Group, L.L.C. dated November 1, 2008.

“JOAs” means (i) that certain Joint Operating Agreement dated November 1, 2007 for Shelley/Michelle Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, (ii) that certain Joint Operating Agreement for dated November 1, 2007 for East Bloxom Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, (iii) that certain Joint Operating Agreement dated November 1, 2007 for Georgetown Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, (iv) that certain Joint Operating Agreement dated November 1, 2007 for Tori Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, (v) that certain Joint Operating Agreement dated November 1, 2007 for West Bloxom Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, and (vi) that certain Joint Operating Agreement dated November 1, 2007 for Kelly Contract Area by and between Windsor Energy Group, L.L.C., Windsor and Contributor, as such agreements have been amended by that certain First Amendment to the Development Agreement dated November 1, 2007 and to each of the Joint Operating Agreements dated as of November 1, 2007 for the East Bloxom, Georgetown, Kelly, Shelley-Michelle, Tori and West Bloxom Prospects by and between Windsor, Contributor and Windsor Energy Group, L.L.C. dated November 1, 2008.

“Law” has the meaning set forth in Section 2.3.

“Lien” means all pledges, claims, liens, charges, restrictions, controls, easements, rights of way, exceptions, reservations, leases, licenses, grants, covenants and conditions, encumbrances and security interests of any kind or nature whatsoever.

“Loan Documents” means the Credit Agreement, dated as of September 30, 2010, by and among the Contributor, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association as amended from time to time.

“Order” has the meaning set forth in Section 2.3.

“Organizational Documents” means with respect to any entity, the certificate of formation, limited liability company agreement or operating agreement, participating agreements, certificate of incorporation, bylaws, certificate of limited partnership, limited partnership agreement and any other governing instrument, as applicable.

“Party” or “Parties” has the meaning set forth in the introductory paragraph hereto.

 

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“Permian Assets” has the meaning set forth in the Recitals hereto.

“Permit” has the meaning set forth in Section 2.3.

“Permitted Liens” means (a) Liens (including mechanics’, workers’, repairers’, materialmens’, warehousemens’, landlord’s and other similar Liens) arising in the ordinary course of business that would not individually or in the aggregate materially adversely affect the value of, or materially adversely interfere with the use of, the property subject to them and (b) Liens arising under, or in connection with, the Loan Documents.

“Person” means an individual, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization or other entity.

“Promissory Note” has the meaning set forth in Section 1.3.

“Prospectus” means Diamondback’s final prospectus as filed pursuant to Rule 424 under the Securities Act with the Commission.

“S-1” has the meaning set forth in Section 2.8.

“Securities Act” means Securities Act of 1933, as amended.

“Special Committee” means the Special Committee of the Board of Directors of the Contributor, currently composed of David L. Houston, Donald Dillingham, Craig Groeschel and Scott E. Steller and formed for the purpose of, among other things, reviewing and evaluating the terms and conditions of, and determine the advisability of, the Gulfport Contribution and whether to approve or reject the Gulfport Contribution.

“Subsidiary” means any corporation, partnership, limited liability company, joint venture, trust or other legal entity which the applicable Person owns (either directly or through or together with another Subsidiary) either (i) a general partner, managing member or other similar interest or (ii) (A) more than 50% of the equity interests or (B) more than 50% of the outstanding voting capital stock or other voting equity interests of such corporation, partnership, limited liability company, joint venture or other legal entity.

“Taxes” means all applicable U.S. federal, state, local and foreign income, withholding, property, sales, franchise, employment, transfer, excise and other taxes, tariffs or governmental charges of any nature whatsoever, including estimated taxes, together with penalties, interest or additions to taxes with respect thereto.

“Terminated Agreements” has the meaning set forth in Section 4.8.

“Transaction Documents” has the meaning set forth in Section 2.2.

“Transactions” has the meaning set forth in Section 2.2.

“Underwriting Agreement” means that certain underwriting agreement to be entered into in connection with the IPO by and among Diamondback and the underwriters in the IPO.

 

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“Wexford Contribution” means a transaction or series of related transactions pursuant to which DB Energy Holdings LLC (“DB Holdings”), an entity controlled by Wexford Capital LP (“Wexford”), contributes all of the outstanding equity interests in Windsor Permian LLC (“Windsor”) to Diamondback in return for shares of Common Stock. For the avoidance of doubt, at the time all the outstanding equity interests in Windsor are contributed to Diamondback, Windsor shall own all of the outstanding equity interests of Windsor UT LLC.

“Windsor Entity” means Windsor and Windsor Energy Group, L.L.C.

8.2 Entire Agreement. This Agreement, together with the other Transaction Documents and all schedules, exhibits, annexes or other attachments hereto or thereto, and the certificates, documents, instruments and writings that are delivered pursuant hereto or thereto, constitutes the entire agreement and understanding of the Parties in respect of the subject matter hereof and supersedes all prior understandings, agreements or representations by or among the Parties, written or oral, to the extent they relate in any way to the subject matter hereof. Except as provided in Article 7, there are no third party beneficiaries having rights under or with respect to this Agreement.

8.3 Assignment; Binding Effect. No Party may assign either this Agreement or any of its rights, interests or obligations hereunder without the prior written approval of the other Party, and any such assignment by a Party without prior written approval of the other Party will be deemed invalid and not binding on such other Party. All of the terms, agreements, covenants, representations, warranties and conditions of this Agreement are binding upon, inure to the benefit of and are enforceable by, the Parties and their respective successors and permitted assigns.

8.4 Notices. All notices, requests and other communications provided for or permitted to be given under this Agreement must be in writing and must be given by personal delivery, by certified or registered United States mail (postage prepaid, return receipt requested), by a nationally recognized overnight delivery service for next day delivery, or by facsimile transmission, to the intended recipient at the address set forth for the recipient on the signature page (or to such other address as any Party may give in a notice given in accordance with the provisions hereof). All notices, requests or other communications will be effective and deemed given only as follows: (i) if given by personal delivery, upon such personal delivery, (ii) if sent by certified or registered mail, on the fifth Business Day after being deposited in the United States mail, (iii) if sent for next day delivery by overnight delivery service, on the date of delivery as confirmed by written confirmation of delivery, or (iv) if sent by facsimile, upon the transmitter’s confirmation of receipt of such facsimile transmission, except that if such confirmation is received after 5:00 p.m. (in the recipient’s time zone) on a Business Day, or is received on a day that is not a Business Day, then such notice, request or communication will not be deemed effective or given until the next succeeding Business Day. Notices, requests and other communications sent in any other manner, including by electronic mail, will not be effective.

8.5 Specific Performance; Remedies. Each Party acknowledges and agrees that the other Party would be damaged irreparably if any provision of this Agreement were not performed in accordance with its specific terms or were otherwise breached. Accordingly, the Parties will be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement and to enforce specifically this Agreement and its provisions in any action or

 

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proceeding instituted in any state or federal court sitting in Oklahoma City, Oklahoma having jurisdiction over the Parties and the matter, in addition to any other remedy to which they may be entitled, at law or in equity. Except as expressly provided herein, the rights, obligations and remedies created by this Agreement are cumulative and in addition to any other rights, obligations or remedies otherwise available at law or in equity. Nothing herein will be considered an election of remedies.

8.6 Headings. The article and section headings contained in this Agreement are inserted for convenience only and will not affect in any way the meaning or interpretation of this Agreement.

8.7 Governing Law. This Agreement will be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to any choice of law principles.

8.8 Amendment; Extensions; Waivers. No amendment, modification, replacement, termination or cancellation of any provision of this Agreement will be valid, unless the same is in writing, makes reference to this Agreement and the provision(s) to be amended, modified, replaced, terminated or canceled and is signed by Contributor and Diamondback. Each waiver of a right hereunder does not extend beyond the specific event or circumstance giving rise to the right. No waiver by any Party of any default, misrepresentation or breach of warranty or covenant hereunder, whether intentional or not, may be deemed to extend to any prior or subsequent default, misrepresentation or breach of warranty or covenant hereunder or affect in any way any rights arising because of any prior or subsequent such occurrence. Neither the failure nor any delay on the part of any Party to exercise any right or remedy under this Agreement will operate as a waiver thereof, nor does any single or partial exercise of any right or remedy preclude any other or further exercise of the same or of any other right or remedy.

8.9 Severability. The provisions of this Agreement will be deemed severable and the invalidity or unenforceability of any provision will not affect the validity or enforceability of the other provisions hereof.

8.10 Expenses. Except as otherwise expressly provided in this Agreement, each Party will bear its own costs and expenses incurred in connection with the preparation, execution and performance of this Agreement and the Transactions, including all fees and expenses of agents, representatives, financial advisors, legal counsel and accountants. Windsor and any other parties to the Wexford Contribution will bear their own respective costs and expenses incurred in connection with the preparation, execution and performance of the transactions contemplated by the Wexford Contribution, including all fees and expenses of agents, representatives, financial advisors, legal counsel and accountants and Contributor shall have no liability or responsibilities for any such costs or expenses. All fees and expenses incurred in connection with the IPO, including, without limitation, the preparation and filings of the S-1 shall be borne solely and entirely by Diamondback with the exception of any underwriter discounts incurred in connection with any sale of shares of Common Stock by Contributor in the IPO which such discounts and commissions shall borne by the Contributor.

 

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8.11 Counterparts; Effectiveness. This Agreement may be executed in one or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument. This Agreement will become effective when one or more counterparts have been signed by each Party and delivered to the other Party.

8.12 Construction. This Agreement has been freely and fairly negotiated among the Parties. If an ambiguity or question of intent or interpretation arises, this Agreement will be construed as if drafted jointly by the Parties and no presumption or burden of proof will arise favoring or disfavoring any Party because of the authorship of any provision of this Agreement.

[SIGNATURE PAGE FOLLOWS]

 

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IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed as of the date stated in the introductory paragraph of this Agreement.

 

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SCHEDULE 2.5

Outstanding Equity Rights

Options to acquire an aggregate of 3.7% of the Common Stock issued and outstanding after giving effect to the IPO have been reserved for issuance to certain key employees of Diamondback and its subsidiaries.

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EXHIBIT A

Form of Promissory Note

[attached]

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PROMISSORY NOTE

 

$		, 2012

FOR VALUE RECEIVED, the undersigned, Diamondback Energy, Inc., a Delaware corporation (“Maker”), promises to pay to the order of Gulfport Energy Corporation, a Delaware corporation (“Payee”), at 14313 N. May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, or any other place as the Payee or any other holder hereof shall designate in writing to Maker, the principal sum of             ($            ) in lawful money of the United States of America, with interest on the principal balance remaining unpaid from time to time (a) from the date of this Note until the Maturity Date at zero percent per annum and (b) at any time after the Maturity Date at the rate equal to the lesser of (i) the maximum rate permitted by applicable law (the “Maximum Rate”), and (ii) ten percent (10%) per annum. Interest shall be computed on a per annum basis of a year of 360 days and for the actual number of days elapsed unless such calculation would result in a rate greater than the Maximum Rate, in which case interest shall be computed on a per annum basis of a year of 365 days.

The principal balance of this Note together with all accrued and unpaid interest shall be due and payable on the earliest to occur of (such date the “Maturity Date”): (a) funding of the IPO; (b)             , 2012 [the fifth business day after the date of the note]; and (c) acceleration of the principal balance hereof pursuant to the terms of this Note. As used herein “IPO” shall have the meaning given such term in that certain Contribution Agreement, dated as of             , 2012, by and between Maker and Payee, as the same may be amended from time to time (the “Contribution Agreement”).

Maker shall have the right to prepay, at any time and from time to time without premium or penalty, the entire unpaid principal balance of this Note or any portion thereof. All payments under this Note shall be applied first to any accrued and unpaid interest as of such date and second to the outstanding principal balance.

All agreements between Maker and the holder of this Note, whether now existing or hereafter arising and whether written or oral, are expressly limited so that in no contingency or event whatsoever, whether by acceleration of this Note or otherwise, shall the amount paid, or agreed to be paid, to the holder hereof for the use, forbearance or detention of the money to be loaned hereunder or otherwise, exceed the Maximum Rate. If from any circumstances whatsoever fulfillment of any provision of this Note or of any other document evidencing, securing or pertaining to the indebtedness evidenced hereby, at the time performance of such provision shall be due, shall involve transcending the limit of validity prescribed by law, then, ipso facto, the obligation to be fulfilled shall be reduced to the limit of such validity, and if from any such circumstances the holder of this Note shall ever receive as interest under this Note or any other document evidencing, securing or pertaining to the indebtedness evidenced hereby or otherwise an amount that would exceed the Maximum Rate, such amount that would be excessive interest shall be applied to the reduction of the principal amount owing under this Note or on account of any other indebtedness of Maker to the holder hereof relating to this Note, and not to the payment of interest, or if such excessive interest exceeds the unpaid balance of principal of this Note and such other indebtedness, such excess shall be refunded to Maker. In

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determining whether or not the interest paid or payable with respect to any indebtedness of Maker to the holder hereof, under any specific contingency, exceeds the Maximum Rate, Maker and the holder hereof shall, to the maximum extent permitted by applicable law, (a) characterize any nonprincipal payment as an expense, fee or premium rather than as interest, (b) exclude voluntary prepayments and the effects thereof, (c) amortize, prorate, allocate and spread the total amount of interest throughout the full term of such indebtedness so that the actual rate of interest on account of such indebtedness is uniform throughout the term thereof, and/or (d) allocate interest between portions of such indebtedness, to the end that no such portion shall bear interest at a rate greater than that permitted by law.

The entire unpaid principal balance of, and all accrued and unpaid interest on, this Note shall immediately be due and payable upon the occurrence of any of the following: (a) failure by Maker to pay any principal amount when due; (b) commencement of a voluntary case against Maker under Title 11 of the United States Code; or (c) the filing of an answer or other pleading admitting or failing to deny the material allegations of a petition filed against Maker commencing an involuntary case under said Title 11 or failure to timely controvert the material allegations of such petition.

If Payee or any other holder hereof expends any effort in any attempt to enforce payment of all or any part or installment of any sum due the holder hereunder, or if this Note is placed in the hands of any attorney for collection, or if it is collected through any legal proceedings, Maker agrees to pay all collection costs and fees incurred by the holder, including attorneys’ fees.

All notices, requests and other communications under this Note will be effective and deemed given if delivered in accordance with Section 8.4 of the Contribution Agreement.

This Note shall be governed by and construed in accordance with the laws of the State of Delaware and the applicable laws of the United States of America.

DIAMONDBACK ENERGY, INC.

By:                                                                                                           

Name:                                                                                                  

Title:                                                                                                    

 

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EXHIBIT B

Form of Assignment

[attached]

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ASSIGNMENT, CONVEYANCE AND BILL OF SALE

STATE OF TEXAS                 )

                                                   ) ss.            KNOW ALL MEN BY THESE PRESENTS

COUNTY OF                           )

THIS ASSIGNMENT, CONVEYANCE AND BILL OF SALE (“Assignment”) is effective as of             , 2012, at 7:00 a.m. Central Time (“Effective Time”), and is from Gulfport Energy Corporation, a Delaware corporation, with an address of 14313 N. May Avenue, Suite 100, Oklahoma City, Oklahoma 73134 (“Assignor”), to             , a             , whose address is 14301 Caliber Drive, Suite 300, Oklahoma City, Oklahoma 73134 (“Assignee”).

WHEREAS, Assignor and Diamondback Energy, Inc. have entered into that certain Contribution Agreement dated May 7, 2012 (the “Contribution Agreement”);

WHEREAS, pursuant to the Contribution Agreement, Assignor has agreed to contribute, transfer, assign, convey and deliver to Assignee, and Assignee has agreed to acquire and accept, all of Assignor’s right, title and interest held in the Permian Assets (as defined in the Contribution Agreement);

WHEREAS, the Permian Assets are comprised of all Assignor’s oil and gas interests and properties located in Andrews, Crockett, Ector, Howard, Midland, Reagan, Sutton and Upton Counties, Texas (the “Lands”); and

WHEREAS, capitalized terms used herein but not defined herein shall have the meaning given such terms in the Contribution Agreement.

NOW, THEREFORE, KNOW ALL MEN BY THESE PRESENTS:

Section 1. Assignment. For One Hundred Dollars ($100.00) and other good and valuable consideration, the receipt and sufficiency of which Assignor acknowledges, Assignor bargains, sells, assigns, and conveys to Assignee and its successors and assigns, all of Assignor’s right, title, and interest in and to the Lands which include the following real and personal properties (collectively, “Properties”), subject to the terms and conditions of this Assignment and all applicable instruments of record in Andrews, Crockett, Ector, Howard, Midland, Reagan, Sutton and Upton Counties, Texas:

(a) The oil, gas and minerals leases described on Exhibit “A” and all other oil, gas and minerals leases (including subleases), together with all operating rights, working interests, leasehold interests, oil and gas interests, net revenue interests, reversionary rights, payments out of production, contractual rights to explore for, develop and produce oil and gas, and other similar rights and agreements, whether producing or non-producing, and any other oil, gas or other leasehold or mineral rights of any type covering or pertaining to the Lands (the “Leases”).

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(b) All oil, gas, water, injection, disposal and other wells located or bottomed or completed in, on or under the Lands, whether producing, shut-in or temporarily abandoned, including, but not limited to, those wells described on Exhibit “B” (the “Wells”).

(c) All rights, titles and interests arising under unitization, pooling and/or unitization agreements, pooling declarations or designations and statutorily, judicially or administratively created drilling, spacing and/or production units or field wide units related to the Leases or the Lands or to the Wells (with respect to any of the foregoing, whether recorded or unrecorded), insofar as the same are attributable or allocated to the Leases, the Lands, or the Wells (the “Units,” the Units, together with the Leases, the Lands and the Wells, the “Real Property Interests”).

(d) All tangible personal property, equipment, fixtures and improvements situated upon the lands covered by the Real Property Interests or lands pooled or unitized therewith or used or obtained in connection therewith, including, but not limited to, pumps, well equipment (surface and subsurface), casing, tanks, lines and facilities, sulfur recovery facilities, compressors, compressor stations, dehydration facilities, treating facilities, pipeline gathering lines, flow lines, transportation lines (including long lines and laterals), valves, meters, separators, tanks, tank batteries, and other fixtures and inventory (the “Equipment”).

(e) All saltwater disposal systems related to the Leases and/or the Wells, including, but not limited to, all wells, pumps, tanks, pipes, facilities and other equipment and property held or used for the handling, processing, treating, storing and/or disposal of saltwater produced from any of the Wells, whether or not located on the Leases or the Lands (the “Disposal Facilities,” which together with the Equipment are described in part on Exhibit “C”).

(f) All easements, surface leases, fee lands, rights of way, disposal permits and agreements and all other rights, privileges, benefits and powers with respect to the use and occupation of the surface or the subsurface applicable to the Leases or the Lands, or relating or pertaining to the Wells, to the Equipment, or the Disposal Facilities, and all permits, licenses, certificates, authorizations, registrations, orders, waivers, variances and approvals granted by, or which have been applied for or are otherwise pending before, governmental authority pertaining to the ownership and/or operation of the Real Property Interests, the Equipment or the Disposal Facilities or otherwise relating thereto (the foregoing being described in part on Exhibit “D”).

(g) To the extent assignable, all of the following which pertain or are applicable to the Leases, the Wells and the Disposal Facilities (or any of them) or the oil, condensate, gas, casinghead gas and other liquid or gaseous hydrocarbons (the “Hydrocarbons”) produced from the Lands, the Leases or Wells, including, but not limited to, those described on Exhibit “E”, to wit: (i) all operating agreements and unit agreements; (ii) all agreements for the marketing, gathering, transportation and/or processing of Hydrocarbons, including interests and rights, if any, with respect to any prepayments, take-or-pay, buydown and buyout agreements; (iii) contracts and contractual rights constituting a part of the chain of title to Assignor’s rights or interests in the Leases or by which Assignor’s rights in the Leases were acquired (to the extent any portion of said agreements remain executory), including (where applicable) farmout agreements and the like; (iv) all bottomhole agreements, area of mutual interest agreements, acreage contribution agreements, options, leases of equipment or facilities, joint venture agreements, pooling agreements, and gas balancing agreements; and (v) those other contracts and agreements pertaining to the Leases, the Wells or the Disposal Facilities and which are listed on Exhibit “E” (but not otherwise) (any or all of the foregoing, the “Related Contracts”).

 

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(h) All Hydrocarbons in, on, under or produced from the Real Property Interests or any interests pooled or unitized therewith from and after the Effective Time, including Hydrocarbons in storage severed after the Effective Time.

(i) To the extent the same are assignable or transferable and, further, to the extent the same are related to the Real Property Interests, all claims, rights and causes of action against third parties, asserted and unasserted, known and unknown, but only to the extent such claims, rights and causes of action are attributable to the Real Property Interests and to the period after the Effective Time, and where necessary to give effect to the assignment of such rights, claims and causes of action, Assignor grants to Assignee the right to be subrogated to such rights, claims and causes of action.

(j) All other rights and interests in, to or under or derived from the Real Property Interests, the lands covered thereby or pooled, unitized or directly used or held for use in connection therewith.

(k) Copies of the data and records relating to the foregoing that have been or will be delivered by Assignor to Assignee (“Documents”) subject to the requirements set forth below.

If originals or copies of the Documents have been provided to Assignee, Assignor shall have access to them at reasonable times and upon reasonable notice during regular business hours for as long as any Lease is in effect after the Effective Time. Assignor may, during this period and at its expense, make copies of the Documents upon reasonable request. Without limiting the generality of the two preceding sentences, for a period as long as any Lease is in effect after the Effective Time, Assignee shall not destroy or give up possession of any original or last remaining copy of the Documents without first offering Assignor the opportunity, at Assignor’s expense, to obtain such original or copy.

If any of the above-described interests are excluded from Section 1 of this Assignment because they are not assignable, then, with respect thereto, Assignor will use its commercially reasonable efforts to obtain a waiver of any restrictions on assignment, and if obtained, such interests will thereupon become a part of the Properties.

Section 2. Limited Title Warranty. Assignor warrants and shall forever defend the title to the Properties unto Assignee against every Person whomsoever lawfully claiming or to claim the same or any part thereof by, through, or under Assignor but not otherwise, subject, however, to the Permitted Liens (regardless of whether they are released on or prior to the Effective Time pursuant to the Contribution Agreement) and to any other Liens created, imposed, modified, amended or extended under or pursuant to the Loan Documents which will be released on or prior to the Effective Time pursuant to the Contribution Agreement; it being the intent (without modifying, amending or expanding the scope of the preceding warranty of title) that, as of the Effective Time pursuant to the Contribution Agreement, the Properties will not be encumbered by Liens or other defects in title to which the Properties were not encumbered

 

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as of the time the Properties were originally assigned and conveyed to Assignor, save and except for the Permitted Liens (regardless of whether they are released on or prior to the Effective Time pursuant to the Contribution Agreement) and any other Liens created, imposed, modified, amended or extended under or pursuant to the Loan Documents which will be released on or prior to the Effective Time pursuant to the Contribution Agreement. Assignor further warrants that any conveyance of the Properties at the Effective Time pursuant to this Assignment also conveys, assigns and transfers to Assignor, its successors and assigns, as of the Effective Time, all warranties, claims and causes of action of whatsoever type or character, in contract or in tort, that Assignor now has or may hereafter acquire from its predecessors-in-title to the Properties, with respect to title to the Properties. EXCEPT FOR THE LIMITED WARRANTY EXPRESSED IN THE PRECEDING SENTENCE(S) OF THIS SECTION 2, NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY, OR OTHERWISE, WITH RESPECT TO ASSIGNOR’S TITLE TO ANY OF THE PROPERTIES IS PROVIDED IN THIS ASSIGNMENT.

Section 3. Disclaimer of Other Warranties. EXCEPT FOR THE LIMITED WARRANTY OF TITLE ABOVE MADE, ASSIGNOR MAKES NO WARRANTY OF ANY TYPE IN THIS ASSIGNMENT, WHETHER EXPRESS, STATUTORY, OR IMPLIED. ASSIGNEE HAS INSPECTED AND HAS SATISFIED ITSELF AS TO THE CONDITION OF THE PROPERTIES. THIS ASSIGNMENT IS MADE BY AND ACCEPTED BY ASSIGNEE ON AN “AS IS, WHERE IS” BASIS. ASSIGNOR DISCLAIMS ALL WARRANTIES, INCLUDING:

AS TO THE FITNESS OR CONDITION OR MERCHANTABILITY OF THE WELLS, EQUIPMENT OR DISPOSAL FACILITIES CONVEYED;

AS TO THE PHYSICAL, OPERATIONAL, OR ENVIRONMENTAL CONDITION OF THE PROPERTIES;

AS TO THE OIL, GAS, AND OTHER HYDROCARBON OPERATIONS OF THE PROPERTIES COVERED BY THE TERMS AND CONDITIONS OF ANY LEASES OR OTHER AGREEMENTS THAT ARE A PART OF THE PROPERTIES; AND

AS TO THE ISSUANCE, REISSUANCE, OR TRANSFER OF ANY PERMITS RELATING TO ANY OF THE PROPERTIES.

Section 4. Covered Interests. Notwithstanding any contrary provision of this Assignment or the Contribution Agreement, to the extent that the assignment or conveyance of all or any part of the Properties shall be subject to any consent or approval requirements that are not satisfied or waived prior to the Effective Time, this Assignment shall not convey or be deemed to convey (until such consent or approval requirement has been satisfied or waived) any right, title or interest in and to the Properties to which such requirement relates (herein, a “Covered Interest”); however, (a) the full benefits of ownership of the Covered Interest shall be bargained, sold, conveyed, assigned and transferred unto Assignee hereunder as of the Effective Time, (b) Assignor shall hold legal title to the Covered Interest as nominee for the benefit of Assignee until such consent or approval requirement has been satisfied or waived, (c) Assignor

 

4

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and Assignee shall each continue to use their respective commercially reasonable efforts to procure all required consents and approvals affecting the Covered Interest as soon as reasonably practicable after the Effective Time, and (d) immediately upon procurement of all required consents and approvals affecting the Covered Interest, all right, title and interest of Assignor in and to the Covered Interest shall thereupon automatically be bargained, sold, conveyed and assigned to Assignee hereunder, effective as of the Effective Time; it being expressly understood and agreed that no retention of any right, title or interest in and to any Covered Interest under this Section 4 or any consents or approvals affecting any Covered Interest shall be deemed or construed to be a breach or default of the limited warranty of title expressed in Section 2 of this Assignment or any provision of the Contribution Agreement.

Section 5. Effective Time Allocations. This Assignment shall be effective for all purposes as of the Effective Time. All production from or attributable to the Properties and all products and proceeds attributable thereto, and all other income, proceeds, receipts and credits with respect to the Properties pertaining to the period prior to the Effective Time shall be owned by and belong to Assignor, and all production from or attributable to the Properties and all products and proceeds attributable thereto and all other income, proceeds, receipts and credits respecting the same pertaining to the period from and after the Effective Time shall be owned by and belong to Assignee. Except as otherwise provided in the Contribution Agreement, all costs, expenses, liabilities and obligations attributable or chargeable to the Properties pertaining to the period prior to the Effective Time shall be retained by and shall remain the sole liability and obligation of Assignor and borne and discharged by Assignor, and all costs, expenses, liabilities and obligations attributable to the Properties pertaining to the period after the Effective Time are hereby assumed by and shall be the sole liability and obligation of Assignee and assumed and discharged by Assignee.

Section 6. The Contribution Agreement. This Assignment is made pursuant and subject to all of the terms and conditions of the Contribution Agreement. Except as otherwise provided in the Contribution Agreement, said terms and provisions shall survive the execution and delivery of this Assignment and shall not be merged therein. All terms and conditions of the Contribution Agreement are hereby incorporated in this Assignment by reference and made a part hereof for all purposes.

Section 7. Further Assurances. After the execution hereof, Assignor, without further consideration, will use its commercially reasonable efforts to execute, deliver and (if applicable) file or record or cause to be executed, delivered and filed or recorded, such good and sufficient instruments of conveyance and transfer and take such other action as may be reasonably required of Assignor to effectively vest in Assignee beneficial and record title to the Properties and, if applicable, to put Assignee in actual possession of the Properties. With respect to interests in Leases issued by the state or a subdivision thereof included within the Properties and that require filings with governmental agencies before they may be assigned, Assignor and Assignee will each use its commercially reasonable efforts to file the appropriate documents and take any other steps necessary to obtain official approval of the assignments. With respect to any Lease issued by the state or any agency thereof requiring consent to transfer, Assignor shall hold title thereto for the express benefit of Assignee until agency approval of such transfer has been obtained.

 

5

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Section 8. Miscellaneous.

(a) The provisions of this Assignment will be deemed severable and the invalidity or unenforceability of any provision will not affect the validity or enforceability of the other provisions hereof.

(b) All covenants and agreements in this Assignment bind and inure to the benefit of the heirs, successors, and assigns of Assignor and Assignee; are covenants running with the Lands; and are effective as stated whether or not the covenants and agreements are memorialized in assignments and other conveyances executed and delivered by the parties and their respective heirs, successors, and assigns from time to time.

(c) Recitation of or reference to any agreement or other instrument in this Assignment, including, without limitation, its exhibits, does not operate to ratify, confirm, revise, or reinstate the agreement or instrument if it has previously lapsed or expired.

(d) This Assignment will be governed by and construed in accordance with the Laws of the State of Texas, without giving effect to any choice of law principles.

(e) The word includes and its syntactical variants mean “includes, but not limited to” and its corresponding syntactical variants. The rule of ejusdem generis may not be invoked to restrict or limit the scope of the general term or phrase followed or preceded by an enumeration of particular examples.

(f) All exhibits referenced in and attached to this Assignment are incorporated into it.

(g) This Assignment may be executed in counterparts, all of which together will be considered one instrument.

[SIGNATURE PAGE FOLLOWS]

 

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IN WITNESS WHEREOF, the parties have caused this Assignment to be executed as of the date stated in the introductory paragraph of this Assignment.

 

 

 

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STATE OF                     )

                                         ) ss.

COUNTY OF                 )

This instrument was acknowledged before me on this             day of             , 2012 by             , as             of GULFPORT ENERGY CORPORATION, on behalf of said corporation.

 

My Commission No.:

My Commission Expires:

(SEAL)

STATE OF                     )

                                         ) ss.

COUNTY OF                 )

This instrument was acknowledged before me on this             day of             , 2012 by             , as             of             , on behalf of said             .

 

My Commission No.:

My Commission Expires:

(SEAL)

 

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EXHIBIT C

Form of Investor Rights Agreement

[attached]

Exhibit 10.19

MASTER DRILLING AGREEMENT

THIS MASTER DRILLING AGREEMENT (this “Agreement”) is made and entered into to be effective as of the 1st day of January 2012, by and between WINDSOR PERMIAN LLC (“Operator”) and BISON DRILLING AND FIELD SERVICES LLC (“Contractor”).

RECITALS

A. Contractor is the owner of certain drilling rigs located in the Permian Basin, and being more particularly described as Bison Rig 41, Bison Rig 42, Bison Rig 56 and Bison Rig 62 (referred to as the “Rigs”); and

B. Operator desires to use the Rigs in connection with Operator’s exploration for oil and gas and as provided herein.

NOW, THEREFORE, in consideration of the premises, covenants and conditions herein, and other valuable consideration, the receipt and sufficiency of which is hereby acknowledged, Operator and Contractor hereby agree as follows:

1. Form of Drilling Agreement. The terms and conditions pursuant to which each of the Rigs shall be used and operated shall be as set forth in the Drilling Bid Proposal and Day work Drilling Contract attached hereto as Exhibit “A” (the “Drilling Contract”). A separate Drilling Contract shall be deemed to apply to each well drilled under this Agreement.

2. Term. This Agreement may be terminated at the option of either party by giving the other party thirty (30) calendar day’s written notice to that effect, but neither party hereto shall, by the termination of this Agreement, be relieved of its respective obligations arising from or incident to a Drilling Contract being performed hereunder prior to the time this Agreement is terminated.

3. Purchase of Services. This Agreement shall control and govern any and all use of the Rigs by Contractor for Operator (the “Services”). The Services will be as requested by Operator to Contractor and will be defined by separate orders (either verbal or written) (each an “Order”). This Contract shall be deemed to be incorporated in full in every Order. Operator shall endeavor to provide written confirmation of any oral Orders within ten (10) working days after same are given, but the failure to do so shall not invalidate the Order or the obligations of the parties.

4. Obligation to Request/Accept Work. Operator shall be obligated to order Services from Contractor and Operator shall be obligated to provide Services to Operator insofar and only insofar as to the use of two (2) of the rigs. The parties shall be relieved of the obligation as to the use of the rigs during the period of time when total loss, destruction or breakdown causes the rig to be unavailable for commencement of a Drilling Contract. This Agreement does not obligate Operator to issue any Order to Contractor nor does it obligate Contractor to accept an Order from Operator as to the use of more than two (2) rigs.

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5. Notices. All notices or other communications hereunder shall be in writing and may be effected by personal delivery, registered or certified mail, postage prepaid with return receipt requested or by email. Mailed notices shall be addressed to the parties at the addresses appearing below, but each party may change its address by written notice to the other party in accordance with this Agreement. Notices delivered personally shall be deemed communicated as of actual receipt; mailed notices shall be deemed communicated upon receipt, refusal or as of the first attempted date of delivery if unclaimed; and email notices shall be deemed communicated as of the date of actual transmission.

 

If to Operator:		Windsor Permian LLC 500 West Texas, Suite 1210 Midland, Texas 79707
		Attention: Travis Stice Email: tstice@windsorenergy.com
If to Contractor:		Bison Drilling and Field Services LLC 11800 HWY 191 Midland, Texas 79707
		Attention: Baron Honea Email: bhonea@windsorenergy.com

6. Entire Agreement. This Agreement constitutes the entire agreement between the parties hereto pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations, and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

7. Assignment. Neither party shall assign this Agreement or any part hereof, nor shall either party assign or delegate any of its rights or obligations hereunder, without the prior written consent of the other. Any purported assignment made without such consent shall be void and of no force and effect. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective permitted successors, assigns, and legal representatives.

8. Amendment. This Agreement may be amended only by an instrument in writing executed by the parties hereto.

9. Waiver. Any of the terms, covenants, representations, warranties, or conditions hereof may be waived only by a written instrument executed by or on behalf of the party hereto waiving compliance. The failure of any party at any time or times to require performance of any provision hereof shall in no manner affect the right of such party at a later time to enforce the performance of such provision or any other provisions hereof.

10. Governing Law. This Agreement shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might refer construction of such provisions to the laws of another jurisdiction.

 

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11. Execution Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument. All such counterparts together shall constitute for all purposes one agreement.

IN WITNESS WHEREOF, Operator and Contractor have executed this Agreement as of the day and year first written above.

 

 

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FORM OF

EXHIBIT A

NOTE: This form contract is a suggested guide only and use of this form or any variation thereof shall be at the sole discretion and risk of the user parties. Users of the form contract or any portion or variation thereof are encouraged to seek the advice of counsel to ensure that their contract reflects the complete agreement of the parties and applicable law. The International Association of Drilling Contractors disclaims any liability whatsoever for loss or damages which may result from use of the form contract or portions or variations thereof. Computer generated form, reproduced under license from IADC.

Revised April, 2003

INTERNATIONAL ASSOCIATION OF DRILLING CONTRACTORS

DRILLING BID PROPOSAL

AND

DAYWORK DRILLING CONTRACT – U.S.

THIS CONTRACT CONTAINS PROVISIONS RELATING TO INDEMNITY,

RELEASE OF LIABILITY, AND ALLOCATION OF RISK –

SEE PARAGRAPHS 4.9, 6.3(c), 10,12, AND 14

This Contract is made and entered into on the date hereinafter set forth by and between the parties herein designated as “Operator” and “Contractor.”

 

		OPERATOR:
		Address:
		CONTRACTOR:
		Address:

IN CONSIDERATION of the mutual promises, conditions and agreements herein contained and the specifications and special provisions set forth in Exhibit “A” and Exhibit “B” attached hereto and made a part hereof (the “Contract”), Operator engages Contractor as an independent contractor to drill the hereinafter designated well or wells in search of oil or gas on a Daywork Basis.

For purposes hereof, the term “Daywork” or “Daywork Basis” means Contractor shall furnish equipment, labor, and perform services as herein provided, for a specified sum per day under the direction, supervision and control of Operator (inclusive of any employee, agent, consultant or subcontractor engaged by Operator to direct drilling operations). When operating on a Daywork Basis, Contractor shall be fully paid at the applicable rates of payment and assumes only the obligations and liabilities stated herein. Except for such obligations and liabilities specifically assumed by Contractor, Operator shall be solely responsible and assumes liability for all consequences of operations by both parties while on a Daywork Basis, including results and all other risks or liabilities incurred in or incident to such operations.

1. LOCATION OF WELL:

 

 

 

 

 

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Locations described above are for well and Contract identification only and Contractor assumes no liability whatsoever for a proper survey or location stake on Operator’s lease.

2. COMMENCEMENT DATE:

Contractor agrees to use reasonable efforts to commence operations for the drilling of the well by the              day of                 , 20    , or                                                                                                                                                                                                         

 

 

3. DEPTH:

3.1 Well Depth: The well(s) shall be drilled to a depth of approximately              feet, or to the              formation, whichever is deeper, but the Contractor shall not be required hereunder lo drill said well(s) below a maximum depth of              feet, unless Contractor and Operator mutually agree to drill to a greater depth.

4. DAYWORK RATES:

Contractor shall be paid at the following rates for the work performed hereunder.

4.1 Mobilization: Operator shall pay Contractor a mobilization fee of $             or a mobilization day rate of $             per day. This sum shall be due and payable in full at the time the rig is rigged up or positioned at the well site ready to spud. Mobilization shall include:

 

 

 

 

4.2 Demobilization: Operator shall pay Contractor a demobilization fee of $             or a demobilization day rate during tear down of $             per day, provided however that no demobilization fee shall be payable if the Contract is terminated due to the total loss or destruction of the rig. Demobilization shall include:

 

 

 

 

4.3 Moving Rate: During the time the rig is in transit to or from a drill site, or between drill sites, commencing on Spud , Operator shall pay Contractor a sum of $             per twenty-four (24) hour day.

4.4 Operating Day Rate: For work performed per twenty-four (24) hour day with              man crew the operating day rate shall be:

 

Depth Intervals

From

To

Without Drill Pipe

With Drill Pipe

$             per day

$             per day

$             per day

$             per day

Using Operator’s drill pipe $             per day.

The rate will begin when the drilling unit is rigged up at the drilling location, or positioned over the location during marine work, and ready to commence operations; and will cease when the rig is ready to be moved off the local if under the above column “With Drill Pipe” no rates are specified, the rate per twenty-four hour day when drill pipe is in use shall be the applicable rate specified in the column “Without Drill Pipe” plus compensation for any drill pipe actually used at the rates specified below, computed on the basis of the maximum drill pipe in use at any time during each twenty-four hour day.

 

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DRILL PIPE RATE PER 24-HOUR DAY

 

Straight Hole

Size

Grade

Directional or Uncontrollable Deviated Hole

Size

Grade

$

per ft.

$

per ft.

$

per ft.

$

per ft.

$

per ft.

$

per ft.

Directional or uncontrolled deviated hole will be deemed to exist when deviation exceeds              degrees or when the change of angle exceeds              degrees per one hundred feet.

Drill pipe shall be considered in use not only when in actual use but also while it is being picked up or laid down. When drill pipe is standing in the derrick, it shall not be considered in use, provided, however, that if Contractor furnishes special strings of drill pipe, drill collars, and handling tools as provided for in Exhibit “A”, the same shall be considered in use at all times when on location or until released by Operator. In no event shall fractions of an hour be considered in computing the amount of time drill pipe is in use but such time shall be computed to the nearest hour, with thirty minutes or more being considered a full hour and less than thirty minutes not to be counted.

4.5 Repair Time: In the event it is necessary to shut down Contractor’s rig for repairs, excluding routine rig servicing, Contractor shall be allowed compensation at the applicable rate for such shut down time up to a maximum of              hours for any one rig repair job, but not to exceed              hours of such compensation for any calendar month. Thereafter, Contractor shall be compensated at a rate of $             per twenty-four (24) hour day. Routine rig servicing shall include, but not be limited to, cutting and slipping drilling line, changing pump or swivel expendables, testing BOP equipment, lubricating rig, and                                                                          

		.

4.6 Standby Time Rate: $             per twenty-four (24) day. Standby time shall be defined to include time when the rig is shut down although in readiness to begin or resume operations but Contractor is waiting on orders of Operator or on materials, services or other items to be furnished by Operator.

4.7 Drilling Fluid Rates: When drilling fluids of a type and characteristic that increases Contractor’s cost of performance hereunder, including, but not limited to, oil-based mud or potassium chloride, are in use, Operator shall pay contractor in addition to the operating rate specified above:

 

(a)

$             per man per day for Contractor’s rig-site personnel,

(b)

$             per day additional operating rate; and

(c)

Cost of all labor, material and services plus              hours operating rate to clean rig and related equipment.

4.8 Force Majeure Rate: $             per twenty-four (24) hour day for any continuous period that normal operations are suspended or cannot be carried on due to conditions of Force Majeure: as defined in Paragraph 17 hereof. It is, however, understood that subject to Subparagraph 6.3 below, Operator can release the rig in accordance with Operator’s right to direct stoppage of the work, effective when conditions will permit the rig to be moved from the location.

4.9 Reimbursable Costs: Operator shall reimburse Contractor for the costs of material, equipment, work or services which are to be furnished by Operator as provided for herein but which for convenience are actually furnished by Contractor at Operator’s request, plus              percent for such cost of handling. When, at Operator’s request and with Contractor’s agreement, the Contractor furnishes or subcontracts for certain items or services which Operator is required herein to provide, for purposes of the indemnity and release provisions of this Contract, said items or services shall be deemed to be Operator furnished items or services. Any subcontractors so hired shall be deemed to be Operator’s contractor, and Operator shall not be relieved of any of its liabilities in connection therewith.

 

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4.10 Revision In Rates: The rates and/or payments herein set forth due to Contractor from Operator shall be revised to reflect the change in costs if the costs of any of the items hereinafter listed shall vary by more than      percent from the costs thereof on the date of this Contract or by the same percent after the date of any revision pursuant to this Subparagraph:

 

(a)

Labor costs, Including all benefits, of Contractor’s personnel;

 

(b)

Contractor’s cost of insurance premiums;

 

(c)

Contractor’s cost of fuel, including all taxes and fees; the cost per gallon/MCF being $            ;

 

(d)

Contractor’s cost of catering, when applicable;

 

(e)

If Operator requires contractor to increase or decrease the number of Contractor’s personnel;

 

(f)

Contractor’s cost of spare parts and supplies with the understanding that such spare parts and supplies constitute      percent of the operating rate and that the parties shall use the U.S. Bureau of Labor Statistics Oil Field and Gas Field Drilling Machinery Producer Price Index (Series ID WPU119102) to determine to what extent a price variance has occurred in said spare parts and supplies;

 

(g)

If there is any change in legislation or regulations in the area in which contractor is working or other unforeseen, unusual event that alters contractor’s financial burden.

5. TIME OF PAYMENT:

Payment is due by Operator to Contractor as follows:

5.1 Payment for mobilization, drilling and other work performed at applicable rates, and all other applicable charges shall be due, upon presentation of invoice therefor, upon completion of mobilization, demobilization, rig release or at the end of the month in which such work was performed or other charges are incurred, whichever shall first occur. All invoices may be mailed to Operator at the address hereinabove shown, unless Operator does hereby designate that such Invoices shall be mailed as follows:

5.2 Disputed Invoices and Late Payment: Operator shall pay all Invoices within 30 days after receipt except that if Operator disputes an invoice or any part thereof, Operator shall, within fifteen days after receipt of the invoice, notify Contractor of the item disputed, specifying the reason therefor, and payment of the disputed item may be withheld until settlement of the dispute, but timely payment shall be made of any undisputed portion. Any sums (including amounts ultimately paid with respect to a disputed invoice) not paid within the above specified days shall bear interest at the rate of      percent or the maximum legal rate, whichever is less, per month from the due date until paid. If Operator does not pay undisputed items within the above stated time, Contractor may suspend operations or terminate this Contract as specified under Subparagraph 6.3.

6. TERM:

6.1 Duration of Contract: This Contract shall remain in full force and effect until drilling operations are completed on the well or wells specified in paragraph 1 above, or for a term of                      commencing on the date specified in Paragraph 2 above.

6.2 Extension of Term: Operator may extend the term of this Contract for Multi well(s) or for a period of                      by giving notice to Contractor at least      days prior to completion of the well then being drilled or by                                                                      

 

 

6.3 Early Termination:

 

(a)

By Either Party: Upon giving of written notice, either party may terminate this Contract when total loss or destruction of the rig, or a major breakdown with indefinite repair time necessitate stopping operations hereunder.

 

(b)

By Operator: Notwithstanding the provisions of Paragraph 3 with respect to the depth to be drilled, Operator shall have the right to direct the stoppage of the work to be

 

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performed by Contractor hereunder at any time prior to reaching the specified depth, and even though Contractor has made no default hereunder. In such event, Operator shall reimburse Contractor as set forth in Subparagraph 6.4 hereof.

 

(c)

By Contractor: Notwithstanding the provisions of Paragraph 3 with respect to the depth to be drilled, in the event Operator shall become insolvent, or be adjudicated a bankrupt, or file, by way of petition or answer, a debtor’s petition or other pleading seeking adjustment of Operator’s debts, under any bankruptcy or debtor’s relief laws now or hereafter prevailing, or if any such be filed against Operator, or in case a receiver be appointed of Operator or Operator’s property, or any part thereof, or Operator’s affairs be placed in the hands of a Creditor’s Committee, or, following three business days prior written notice to Operator if Operator does not pay Contractor within the time specified in Subparagraph 5.2 all undisputed items due and owing, Contractor may, at its option, (1) elect to terminate further performance of any work under this Contract and Contractor’s right to compensation shall be as set forth in Subparagraph 6.4 hereof, or (2) suspend operations until payment is made by Operator in which event the standby time rate contained in Subparagraph 4.6 shall apply until payment is made by Operator and operations are resumed. In addition to Contractor’s rights to suspend operations or terminate performance under this Paragraph, Operator hereby expressly agrees to protect, defend and Indemnify Contractor from and against any claims, demands and causes of action, including all costs of defense, in favor of Operator, Operators co-venturers, co-lessees and joint owners, or any other parties arising out of any drilling commitments or obligations contained in any lease, farmout agreement or other agreement, which may be affected by such suspension of operations or termination of performance hereunder.

6.4 Early Termination Compensation:

 

(a)

Prior to Commencement: In the event Operator terminates this Contract prior to commencement of operations hereunder, Operator shall pay Contractor as liquidated damages and not as a penalty a sum equal to the standby time rate (Subparagraph 4.6) for a period of      days or a lump sum of                 .

 

(b)

Prior to Spudding: If such termination occurs after commencement of operations but prior to the spudding of the well, Operator shall pay to Contractor the sum of the following: (1) all expenses reasonably and necessarily incurred and to be incurred by Contractor by reason of the Contract and by reason of the premature termination of the work, including the expense of drilling or other crew members and supervision directly assigned to the rig; (2) ten percent (10%) of the amount of such reimbursable expenses; and (3) a sum calculated at the standby time rate for all time from the date upon which Contractor commences any operations hereunder down to such date subsequent to the date of termination as will afford Contractor reasonable time to dismantle its rig and equipment provided, however, if this Contract is for a term of more than one well or for a period of time, Operator shall pay Contractor, in addition to the above, the Force Majeure Rate, less any unnecessary labor, from that date subsequent to termination upon which Contractor completes dismantling its rig and equipment until the end of the term or

				.

 

(c)

Subsequent to spudding: If such termination occurs after the spudding of the well, Operator shall pay Contractor (1) the amount for all applicable rates and all other charges and reimbursements due to Contractor; but in no event shall such sum, exclusive of reimbursements due, be less than would have been earned for              days at the applicable rate “Without Drill Pipe” and the actual amount due for drill pipe used in accordance with the above rates; or (2) at the election of Contractor and in lieu of the foregoing, Operator shall pay Contractor for all expenses reasonably and necessarily incurred and to be incurred by reason of this Contract and by reason of such premature termination plus a lump sum of $            ; provided, however, if this Contract is for a term of more than one well or for a period of time, Operator shall pay Contractor, in addition to the above, the Force Majeure Rate less any unnecessary labor from the date of termination until the end of the term or

 

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7. CASING PROGRAM:

Operator shall have the right to designate the points at which casing will be set and the manner of setting, cementing and testing. Operator may modify the casing program, however, any such modification which materially increases Contractor’s hazards or costs can only be made by mutual consent of Operator and Contractor and upon agreement as to the additional compensation to be paid Contractor as a result thereof.

8. DRILLING METHODS AND PRACTICES:

8.1 Contractor shall maintain well control equipment in good condition at all times and shall use all reasonable means to prevent and control fires and blowouts and to protect the hole.

8.2 Subject to the terms hereof, and at Operator’s cost, at all times during the drilling of the well, Operator shall have the right to control the mud program, and the drilling fluid must be of a type and have characteristics and be maintained by Contractor in accordance with the specifications shown in Exhibit “A”.

8.3 Each party hereto agrees to comply with all laws, rules, and regulations of any federal, state or local governmental authority which are now or may become applicable to that party’s operations covered by or arising out of the performance of this Contract. When required by law, the terms of Exhibit “B” shall apply to this Contract. In the event any provision of this Contract is inconsistent with or contrary to any applicable federal, state or local law, rule or regulation, said provision shall be deemed to be modified to the extent required to comply with said law, rule or regulation, and as so modified said provision and this Contract shall continue in full force and effect.

8.4 Contractor shall keep and furnish to Operator an accurate record of the work performed and formations drilled on the IADC-API Daily Drilling Report Form or other form acceptable to Operator. A legible copy of said form shall be furnished by Contractor to Operator.

8.5 If requested by Operator, Contractor shall furnish Operator with a copy of delivery tickets covering any material or supplies provided by Operator and received by Contractor.

9. INGRESS, EGRESS, AND LOCATION:

Operator hereby assigns to Contractor all necessary rights of ingress and egress with respect to the tract on which the well is to be located for the performance by Contractor of all work contemplated by this Contract. Should Contractor be denied free access to the location for any reason not reasonably within Contractor’s control, any time lost by Contractor as a result of such denial shall be paid for at the standby time rate. Operator agrees at all times to maintain the road and location in such a condition that will allow free access and movement to and from the drilling site in an ordinarily equipped highway type vehicle. If Contractor is required to use bulldozers, tractors, four-wheel drive vehicles, or any other specialized transportation equipment for the movement of necessary personnel, machinery, or equipment over access roads or on the drilling location, Operator shall furnish the same at its expense and without cost to Contractor. The actual cost of repairs to any transportation equipment furnished by Contractor or its personnel damaged as a result of improperly maintained access roads or location will be charged to Operator. Operator shall reimburse Contractor for all amounts reasonably expended by Contractor for repairs and/or reinforcement of roads, bridges and related or similar facilities (public and private) required as a direct result of a rig move pursuant to performance hereunder. Operator shall be responsible for any costs associated with leveling the rig because of location settling.

10. SOUND LOCATION:

Operator shall prepare a sound location adequate in size and capable of properly supporting the drilling rig, and shall be responsible for a casing and cementing program adequate to prevent soil and subsoil wash out. It is recognized that Operator has superior knowledge of the location and access routes to the location, and must advise Contractor of any subsurface conditions, or obstructions (including, but not limited to, mines, caverns, sink holes,

 

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streams, pipelines, power lines and communication lines) which Contractor might encounter while en route to the location or during operations hereunder. [In the event subsurface conditions cause a cratering or shifting of the location surface, or if seabed conditions prove unsatisfactory to properly support the rig during marine operations hereunder, and loss or damage to the rig or its associated equipment results therefrom, Operator shall, without regard to other provisions of this Contract, including Subparagraph 14.1 hereof, reimburse Contractor for all such loss or damage including removal of debris and payment of Force Majeure Rate during repair and/or demobilization if applicable.]

11. EQUIPMENT CAPACITY:

Operations shall not be attempted under any conditions which exceed the capacity of the equipment specified to be used hereunder or where canal or water depths are in excess of      feet. Without prejudice to the provisions of Paragraph 14 hereunder, Contractor shall have the right to make the final decision as to when an operation or attempted operation would exceed the capacity of specified equipment.

12. TERMINATION OF LOCATION LIABILITY:

When Contractor has concluded operations at the well location, Operator shall thereafter be liable for damage to property, personal injury or death of any person which occurs as a result of conditions of the location and Contractor shall be relieved of such liability; provided, however, if Contractor shall subsequently reenter upon the location for any reason, including removal of the rig, any term of the Contract relating to such reentry activity shall become applicable during such period.

13. INSURANCE:

During the life of this Contract, Contractor shall at Contractor’s expense maintain, with an insurance company or companies authorized to do business in the state where the work is to be performed or through a self-insurance program, insurance coverages of the kind and in the amount set forth in Exhibit “A”, insuring the liabilities specifically assumed by Contractor in Paragraph 14 of this Contract. Contractor shall procure from the company or companies writing said insurance a certificate or certificates that said insurance is in full force and effect and that the same shall not be canceled or materially changed without ten (10) days prior written notice to Operator. For liabilities assumed hereunder by Contractor, its insurance shall be endorsed to provide that the underwriters waive their right of subrogation against Operator. Operator will, as well, cause its insurer to waive subrogation against Contractor for liability it assumes and shall maintain, at Operator’s expense, or shall self insure, insurance coverage as set forth in Exhibit “A” of the same kind and in the same amount as is required of Contractor, insuring the liabilities specifically assumed by Operator in Paragraph 14 of this Contract. Operator shall procure from the company or companies writing said insurance a certificate or certificates that said insurance is in full force and effect and that the same shall not be canceled or materially changed without ten (10) days prior written notice to Contractor. Operator and Contractor shall cause their respective underwriters to name the other additionally insured but only to the extent of the indemnification obligations assumed herein.

14. RESPONSIBILITY FOR LOSS OR DAMAGE, INDEMNITY, RELEASE OF LIABILITY AND ALLOCATION OF RISK:

14.1 Contractor’s Surface Equipment: Contractor shall assume liability at all times for damage to or destruction of Contractor’s surface equipment, regardless of when or how such damage or destruction occurs, and Contractor shall release Operator of any liability for any such loss, except loss or damage under the provisions of Paragraph 10 or Subparagraph 14.3.

14.2 Contractor’s in-Hole Equipment: Operator shall assume liability at all times for damage to or destruction of Contractor’s in-hole equipment, including, but not limited to, drill pipe, drill collars, and tool joints, and Operator shall reimburse Contractor for the value of any such loss or damage;: the value to be determined by agreement between Contractor and Operator as current repair costs or      percent of current new replacement cost of such equipment delivered to the well site.

14.3 Contactor’s Equipment - Environmental Loss or Damage: Notwithstanding the provisions of Subparagraph 14.1 above, Operator shall assume liability at all times for damage to or destruction of

 

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Contractor’s equipment resulting from the presence of H₂S₁ CO₂ or other corrosive elements that enter the drilling fluids from subsurface formations or the use of corrosive, destructive or abrasive additives in the drilling fluids.

14.4 Operator’s Equipment: Operator shall assume liability at all times for damage to or destruction of Operator’s or its co-venturcrs’, co-lessees’ or joint owners’ equipment, including, but not limited to, casing, tubing, well head equipment, and platform if applicable, regardless of when or how such damage or destruction occurs, and Operator shall release Contractor of any liability for any such loss or damage.

14.5 The Hole: in the event the hole should be lost or damaged, Operator shall be solely responsible for such damage to or loss of the hole, including the casing therein. Operator shall release Contractor and its suppliers, contractors and subcontractors of any tier of any liability for damage to or loss of the hole, and shall protect, defend and indemnify Contractor and its suppliers, contractors and subcontractors of any tier from and against any and all claims, liability, and expense relating to such damage to or loss of the hole.

14.6 Underground Damage: Operator shall release Contractor and its suppliers, contractors and subcontractor of any tier of any liability for, and shall protect, defend and indemnify Contractor and its suppliers, contractors and subcontractors of any tier from and against any and all claims, liability, and expense resulting from operations under this Contract on account of injury to, destruction of, or loss or impairment of any property right in or to oil, gas, or other mineral substance or water, if at the time of the act or omission causing such injury, destruction, loss, or impairment, said substance had not been reduced to physical possession above the surface of the earth, and for any loss or damage to any formation, strate, or reservoir beneath the surface of the earth.

14.7 Inspection of Materials Furnished by Operator: Contractor agrees to visually inspect all materials furnished by Operator before using same and to notify Operator of any apparent defects therein. Contractor shall not be liable for any loss or damage resulting from the use of materials furnished by Operator, and Operator shall release Contractor from, and shall protect, defend and indemnify Contractor from and against, any such liability.

14.8 Contractor’s Indemnification of Operator: Contractor shall release Operator of any liability for, and shall protect, defend and indemnify Operator from and against all claims, demands, and causes of action of every kind and character, without limit and without regard to the cause or causes thereof or the negligence of any party or parties, arising in connection herewith in favor of Contractor’s employees or Contractor’s subcontractor of any tier (inclusive of any agent or consultant engaged by Contractor) or their employees, or Contractor’s Invitees, on account of bodily injury, death or damage to property. Contractor’s indemnity under this Paragraph shall be without regard to and without any right to contribution from any insurance maintained by Operator pursuant to Paragraph 13. If it is judicially determined that the monetary limits of insurance required hereunder or of the indemnities voluntarily assumed under Subparagraph 14.8 (which Contractor and Operator hereby agree will be supported either by available liability insurance, under which the insurer has no right of subrogation against the indemnities, or voluntarily self-insured, in part or whole) exceed the maximum limits permitted under applicable law, it is agreed that said insurance requirements or indemnities shall automatically be amended to conform to the maximum monetary limits permitted under such law.

14.9 Operator’s Indemnification of Contractor: Operator shall release Contractor of any liability for, and shall protect, defend and indemnify Contractor from and against all claims, demands, and causes of action of every kind and character, without limit and without regard to the cause or causes thereof or the negligence of any party or parties, arising in connection herewith in favor of Operator’s employees or Operator’s contractors of any tier (inclusive of any agent, consultant or subcontractor engaged by Operator) or their employees, or Operator’s invitees, other than those parties identified in Subparagraph 14.8 on account of bodily injury, death or damage to property. Operator’s indemnity under this Paragraph shall be without regard to and without any right to contribution from any insurance maintained by Contractor pursuant to Paragraph 13. If it is judicially determined that the monetary limits of insurance required hereunder or of the indemnities voluntarily assumed under Subparagraph 14.9 (which Contactor and Operator hereby agree will be supported either by available liability insurance, under which the insurer has no right of subrogation against the indemnities, or voluntarily self-insured, in part or whole) exceed the maximum limits permitted under applicable law, it is agreed that said insurance requirements or indemnities shall automatically be amended to conform to the maximum monetary limits permitted under such law.

 

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14.10 Liability for Wild Well: Operator shall be liable for the cost of regaining control of any wild well, as well as for cost of removal of any debris and cost of property remediation and restoration, and Operator shall release, protect, defend and indemnify Contractor and its suppliers, contractors and subcontractors of any tier from and against any liability for such cost.

14.11 Pollution or Contamination: Notwithstanding anything to the contrary contained herein, except the provisions of Paragraphs 10 and 12, it is understood and agreed by and between Contractor and Operator that the responsibility for pollution or contamination shall be as follows:

 

(a)

Contractor shall assume all responsibility for, including control and removal of, and shall protect, defend and indemnify Operator from and against all claims, demands and causes of action of every kind and character arising from pollution or contamination, which originates above the surface of the land or water from spills of fuels, lubricants, motor oils, pipe dope, paints, solvents, ballast, bilge and garbage, except unavoidable pollution from reserve pits, wholly in Contractor’s possession and control and directly associated with Contractor’s equipment and facilities.

 

(b)

Operator shall assume all responsibility for, including control and removal of, and shall protect, defend and indemnify Contractor and its suppliers, contractors and subcontractors of any tier from and against all claims, demands, and causes of action of every kind and character arising directly or indirectly from all other pollution or contamination which may occur during the conduct of operations hereunder, including, but not limited to, that which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas, water or other substance, as well as the use or disposition of all drilling fluids, including, but not limited to, oil emulsion, oil base or chemically treated drilling fluids, contaminated cuttings or cavings, lost circulation and fish recovery materials and fluids. Operator shall release Contractor and its suppliers, contractors and subcontractors of any tier of any liability for the foregoing.

 

(c)

In the event a third party commits an act or omission which results in pollution or contamination for which either Contractor or Operator, for whom such party is performing work, is held to be legally liable, the responsibility therefor shall be considered, as between Contractor and Operator, to be the same as if the party for whom the work was performed had performed the same and all of the obligations respecting protection, defense, indemnity and limitation of responsibility and liability, as set forth in (a) and (b) above, shall be specifically applied.

14.12 Consequential Damages: Subject to and without affecting the provisions of this Contract regarding the payment rights and obligations of the parties or the risk of loss, release and indemnity rights and obligations of the parties, each party shall at all times be responsible for and hold harmless and indemnify the other party from and against its own special, indirect or consequential damages, and the parties agree that special, indirect or consequential damages shall be deemed to include, without limitation, the following: loss of profit or revenue; costs and expenses resulting from business interruptions; loss of or delay in production; loss of or damage for the leasehold loss of or delay in drilling or operating rights; cost of or loss of use of property, equipment, materials and services, including without limitation those provided by contractors or subcontractors of every tier or by third parties; Operator shall at all times be responsible for and hold harmless and indemnify Contractor and its suppliers, contractors and subcontractors of any tier from and against all claims, demands and causes of action of every kind and character in connection with such special, indirect or consequential damages suffered by Operator’s co-owners, co-venturers, co-lessees, farmors, farmees, partners and joint owners.

14.13 Indemnity Obligation: Except as otherwise expressly limited in this Contract, it is the intent of parties hereto that all releases, indemnity obligations and/or liabilities assumed by such parties under terms of this Contract, including, without limitation, Subparagraphs 4.9 and 6.3(c), Paragraphs 10 and 12, and Subparagraphs 14.1 through 14.12 hereof, be without limit and without regard to the cause or causes thereof, including, but not

 

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limited to, pre-existing conditions, defect or ruin of premises or equipment, strict liability, regulatory or statutory liability, products liability, breach of representation or warranty (express or implied), breach of duty (whether statutory, contractual or otherwise) any theory of tort, breach of contract, fault, the negligence of any degree or character (regardless of, whether such negligence is sole, joint, or concurrent, active, passive or gross) of any party or parties, including the party seeking the benefit of the release, indemnity or assumption of liability, or any other theory of legal liability. The indemnities, and releases and assumptions of liability extended by the parties hereto under the provisions of Subparagraphs 4.9 and 6.3 and Paragraphs 10, 12 and 14 shall inure to the benefit of such parties, their co-venturers, co-lessees, joint owners, their parent, holding and affiliated companies and the officers, directors, stockholders, partners, managers, representatives, employees, consultants, agents, servants and insurers of each. Except as otherwise provided herein, such indemnification and assumptions of liability shall not be deemed to create any rights to indemnification in any person or entity not a party to this Contract, either as a third party beneficiary or by reason of any agreement of indemnity between one of the parties hereto and another person or entity not a party to this Contract.

15. AUDIT:

If any payment provided for hereunder is made on the basis of Contractor’s costs, Operator shall have the right to audit Contractor’s books and records relating to such costs. Contractor agrees to maintain such books and records for a period of two (2) years from the date such costs were incurred and to make such books and records readily available to Operator at any reasonable time or times within the period.

16. NO WAIVER EXCEPT IN WRITING:

It is fully understood and agreed that none of the requirements of this Contract shall be considered as waived by either party unless the same is done in writing, and then only by the persons executing this Contract, or other duly authorized agent or representative of the party.

17. FORCE MAJEURE:

Except as provided in this Paragraph 17 and without prejudice to the risk of loss, release and indemnity obligations under this Contract, each party to this Contract shall be excused from complying with the terms of this Contract, except for the payment of monies when due, if and for so long as such compliance is hindered or prevented by a Force Majeure Event. As used in this Contract, “Force Majeure Event” includes; acts of God, action of the elements, wars (declared or undeclared), insurrection, revolution, rebellions or civil strife, piracy, civil war or hostile action, terrorist acts, riots, strikes, differences with workmen, acts of public enemies, federal or state laws, rules, regulations, dispositions or orders of any governmental authorities having jurisdiction in the premises or of any other group, organization or informal association (whether or not formally recognized as a government), inability to procure material, equipment, fuel or necessary labor in the open market, acute and unusual labor or material, equipment or fuel shortages, or any other causes (except financial) beyond the control of either party. Neither Operator nor Contractor shall be required against its will to adjust any labor or similar disputes except in accordance with applicable law. In the event that either party hereto is rendered unable, wholly or in part, by any of these causes to carry out its obligation under this Contract. It is agreed that such party shall give notice and details of Force Majeure in writing to the other party as promptly as possible after its occurrence. In such cases, the obligations of the party giving the notice shall be suspended during the continuance of any inability so caused except that Operator shall be obligated to pay to Contractor the Force Majeure Rata provided for in Subparagraph 4.8 above.

18. GOVERNING LAW:

This Contract shall be construed, governed, interpreted, enforced and litigated, and the relations between the parties determined in accordance with the laws of Texas.

19. INFORMATION CONFIDENTIAL:

Upon written request by Operator, information obtained by Contractor in the conduct of drilling operations on this well, including, but not limited to, depth, formations penetrated, the results of coring, testing and surveying, shall be considered confidential and shall not be divulged by Contractor or its employees, to any person, firm or corporation other than Operator’s designated representatives.

 

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20. SUBCONTRACTS:

Either party may employ other contractors to perform any of the operations or services to be provided or performed by it according to Exhibit “A”.

21. ATTORNEY’S FEES:

If this Contract is placed in the hands of an attorney for collection of any sums due hereunder, or suit is brought on same, or sums due hereunder are collected through bankruptcy or arbitration proceedings, then the prevailing party shall be entitled to recover reasonable attorney’s fees and costs.

22. CLAIMS AND LIENS:

Contractor agrees to pay all valid claims for labor, material, services, and supplies to be furnished by Contractor hereunder, and agrees to allow no lien by such third parties to be fixed upon the lease, the well, or other property of the Operator or the land upon which said well is located.

23. ASSIGNMENT:

Neither party may assign this Contract without the prior written consent of the other, and prompt notice of any such intent to assign shall be given to the other party. In the event of such assignment, the assigning party shall remain liable to the other party as a guarantor of the performance by the assignee of the terms of this Contract. If any assignment is made that materially alters Contractor’s financial burden, Contractor’s compensation shall be adjusted to give effect to any increase or decrease in Contractor’s operating costs.

24. NOTICES AND PLACE OF PAYMENT:

Notices, reports, and other communications required or permitted by this Contract to be given or sent by one party to the other shall be delivered by hand, mailed, digitally transmitted or telecopied to the address hereinabove shown. All sums payable hereunder to Contractor shall be payable at its address hereinabove shown unless otherwise specified herein.

25. CONTINUING OBLIGATIONS:

Notwithstanding the termination of this Contract, the parties shall continue to be bound by the provisions of this Contract that reasonably require some action or forbearance altar such termination.

26. ENTIRE AGREEMENT:

This Contract constitutes the full understanding of the parties, and a complete and exclusive statement of the terms of their agreement, and shall exclusively control and govern all work performed hereunder. All representations, offers, and undertakings of the parties made prior to the effective date hereof, whether oral or in writing, are merged herein, and no other contracts, agreements or work orders, executed prior to the execution of this Contract, shall in any way modify, amend, alter or change any of the terms or conditions set out herein.

27. SPECIAL PROVISIONS:

28. ACCEPTANCE OF CONTRACT:

The foregoing Contract, including the provisions relating to indemnity, release of liability and allocation of risk of Subparagraphs 4.9 and 6.3(c), Paragraphs 10 and 12, and Subparagraphs 14.1 through 14.12, is acknowledged, agreed to and accepted by Operator this      day of                 , 20    .

 

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The foregoing Contract, including the provisions relating to indemnity, release of liability and allocation of risk of Subparagraphs 4.9, 6.3(c), Paragraphs 10 and 12, and Subparagraphs 14.1 through 14.12 is acknowledged, agreed to and accepted by Contractor this             day of             , 2012, which is the effective date of this Contract, subject to rig availability, and subject to all of its terms and provisions, with the understanding that it will not be binding upon Operator until Operator has noted its acceptance, and with the further understanding that unless said Contract is thus executed by Operator within             days of the above date Contractor shall be in no manner bound by its signature thereto.

 

 

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Revised April, 2003

EXHIBIT A

To Daywork Contract dated             , 20        

 

Operator:		Contractor:

Well Name and Number:             

SPECIFICATIONS AND SPECIAL PROVISIONS

 

1.	CASING PROGRAM (See Paragraph 7)

 

Hole Size

Casing Size

Weight

Grade

Approximate Setting Depth

Wait on Cement Time

Conductor

in.

in.

lbs/ft.

ft.

hrs

Surface

in.

in.

lbs/ft.

ft.

hrs

Protection

in.

in.

lbs/ft.

ft.

hrs

Production

in.

in.

lbs/ft.

ft.

hrs

Liner

in.

in.

lbs/ft.

ft.

hrs

in.

in.

lbs/ft.

ft.

hrs

 

2.	MUD CONTROL PROGRAM (See Subparagraph 8.2)

 

From		To		Type Mud		Weight          (lbs./gal.)		Viscosity (Secs)		Water Loss (cc)

 

Other mud specifications:

 

3.	INSURANCE (See Paragraph 13)

 

3.1

Adequate Workers’ Compensation Insurance complying with State Laws applicable or Employers’ Liability Insurance with limits of $             covering all of Contractor’s employees working under this Contract.

 

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3.2

Commercial (or Comprehensive) General Liability insurance, including contractual obligations as respects this Contract and proper coverage for all other obligations assumed in this Contract. The limit shall be $             combined single limit per occurrences for Bodily Injury and Property Damage.

 

3.3

Automobile Public Liability insurance with limits of $             for the death or injury of each person and $             for each accident; and Automobile Public Liability Property Damage insurance with limits of $             for each accident.

 

3.4

In the event operations are over water, Contractor shall carry in addition to the Statutory Workers’ Compensation Insurance, endorsements covering liability under the Longshoremen’s & Harbor Workers’ Compensation Act and Maritime liability including maintenance and cure with limits of $             for each death or injury to one person and $             for any one accident.

 

3.5		Other Insurance:

 

4.	EQUIPMENT, MATERIALS AND SERVICES TO BE FURNISHED BY CONTRACTOR:

The machinery, equipment, tools, materials, supplies, instruments, services and labor hereinafter listed, including any transportation required for such items, shall be provided at the well location at the expense of Contractor unless otherwise noted by this Contract.

 

4.1

Drilling Rig

Complete drilling rig, designated by Contractor as its Rig No.             , the major items of equipment being:

 

Drawworks: Make and Model
Engines: Make, Model, and H.P.
No. on Rig:
Pumps: No. 1 Make, Size, and Power
No. 2 Make, Size, and Power
Mud Mixing Pump: Make, Size and Power
Boilers: Number, Make, H.P. and W.P.
Derrick or Mast: Make, Size and Capacity
Substructure: Size and Capacity:
Rotary Drive: Type
Drill Pipe: Size				ft.
Drill Collars: Number and Size
Blowout Preventers:

 

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Size		Series or Test Pr.		Make & Model		Number

 

B.O.P. Closing Unit:

 

B.O.P. Accumulator:

 

 

5.	EQUIPMENT, MATERIALS AND SERVICES TO BE FURNISHED BY OPERATOR:

The machinery, equipment, tools, materials, supplies, instruments, services and labor hereinafter listed, including any transportation required for such items, shall be provided at the well location at the expense of Operator unless otherwise noted by this Contract.

 

 

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8.	EQUIPMENT, MATERIALS AND SERVICES TO BE FURNISHED BY DESIGNATED PARTY:

The machinery, equipment, tools, materials, supplies, instruments, services, and labor listed as the following numbered items, including any transportation required for such items unless otherwise specified, shall be provided at the well location and at the expense of the party hereto as designated by an X mark in the appropriate column.

 

 

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21

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7.	OTHER PROVISIONS

 

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EXHIBIT B

(See Subparagraph 8.3)

The following clauses, when required by law, are incorporated in the Contract by reference as if fully set out:

 

(1)	The Equal Opportunity Clause prescribed in 41 CFR 60-1.4.

 

(2)	The Affirmative Action Clause prescribed in 41 CFR 60-250.4 regarding veterans and veterans of the Vietnam era.

 

(3)	The Affirmative Action Clause for handicapped workers prescribed in 41 CFR 60-741.4.

 

(4)	The Certification of Compliance with Environmental Laws prescribed in 40 CFR 15.20.

 

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Exhibit 10.20

GAS PURCHASE AGREEMENT

THIS AGREEMENT (“Agreement”) made and entered into as of May 1^st, 2009 by and between FEAGAN GATHERING COMPANY, a Texas Corporation, hereinafter referred to as (“Buyer”) and Windsor Permian LLC, a Texas corporation, hereinafter referred to as (“Seller”).

WITNESSETH

WHEREAS, Seller has or will have available for sale gas production from certain wells located on the acreage (the “Lands”) described in Exhibit “A” attached hereto and made a part hereof; and

WHEREAS, Buyer desires to purchase such gas from Seller and Seller desires to sell such gas to Buyer, pursuant to the terms and provisions described herein.

NOW, THEREFORE, for and in consideration of the mutual covenants and conditions herein contained and other good and valuable consideration, the parties hereto mutually covenant and agree as follows:

I. DEFINITIONS

As used herein, the following terms shall be construed to have meanings as follows:

1.1 The term “day” shall mean a period of twenty-four (24) consecutive hours beginning and ending at eight o’clock (8:00) am. local time.

1.2 The term “month” shall mean a period beginning at eight o’clock (8:00) a.m. on the first day of a calendar month and ending at eight o’clock (8:00) a.m. on the first day of the next succeeding calendar month.

1.3 The term “year” shall mean a period of three hundred sixty five (365) consecutive days beginning and ending at 8:00 am. local time, provided that any such year which contains the date of February 29 shall consist of three hundred sixty six (366) days.

1.4 The term “gas” shall mean natural gas including gas well gas and casinghead gas.

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1.5 The term “Mcf’ shall mean one thousand (1,000) cubic feet and “MMcf” shall mean one million (1,000,000) cubic feet.

1.6 The term “Btu” shall mean British Thermal Unit and the term “MMBtu” shall mean one million (1,000,000) British Thermal Units.

1.7 The term “Psia” shall mean pounds per square inch, absolute.

1.8 The term “Psig” shall mean pounds per square inch, gauge.

1.9 The term “Transporting Pipeline” shall mean the pipeline(s) that connect to MidMar Plant and Chevron Headlee Plant or other Delivery Point(s) where gas is sold or transported for sale.

II. PRELIMINARY ACTS OF PARTIES

2.1 Buyer represents that it owns and operates a Gas Gathering System (the “System”) located in certain portions of Andrews, Ector, Martin and Midland Counties, Texas, sufficient to accept delivery of Seller’s gas at each Receipt Point and deliver such gas for marketing to the Delivery Point(s) described herein.

2.2 Seller represents that it owns or otherwise has the right to sell and deliver all gas subject to this Agreement free from all liens and adverse claims.

2.3 Seller hereby dedicates to this Agreement all gas owned or controlled by Seller produced from the Lands (“Dedicated Gas”), during the term of this Agreement.

III. RECEIPT POINT(S), DELIVERY POINT(S) AND DELIVERY PRESSURE

3.1 The Receipt Point(s) for all gas subject hereto shall be at the interconnection between Buyer’s measurement facilities and the production facilities of Seller’s wells producing from the leases and properties set forth in Exhibit “A” hereto.

3.2 The Delivery Point for all gas subject hereto shall be at the measurement facilities located at one or more points at the end of the System, as may be designated by Buyer, from time to time during the term hereof, at which point Buyer will deliver the gas to a residue gas purchaser. The initial Delivery Point(s) will be the outlet of the Chevron Headlee Plant in Ector County, Texas (“Chevron Headlee Plant”) and the outlet of the MidMar Plant in Andrews County, Texas (“MidMar Plant”).

 

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3.3 Seller shall deliver all Dedicated Gas hereunder at the Receipt Point(s) at the pressure prevailing therein from time to time, not to exceed forty pounds per square inch gauge (40 psig). If any of the wells from the Dedicated Gas are produced become unable to produce at the pressure prevailing from time to time in the System and neither party elects to provide compression, then, at Seller’s request, Dedicated Gas from such well or wells will be permanently released from this Agreement.

3.4 Receipt Points will, from time to time, be added to this Agreement in order for Seller to deliver and Buyer to purchase Dedicated Gas. Receipt Points must be commercially reasonable to connect. For purposes of this agreement, Seller’s Spanish Trail acreage and Hurt acreage as described in Exhibit A are deemed to be commercially reasonable. Seller’s University Lands acreage will be evaluated based on commercial terms and conditions that yield a similar rate of return for Buyer as Spanish Trail and Hurt acreage. If University Lands acreage is determined to not be commercially reasonable to connect, in the determination of either Buyer or Seller, at Seller’s option, University Lands acreage will be permanently released from this Agreement.

3.5 Seller shall be in control and possession of all gas purchased and sold hereunder and responsible for any damage or injury caused thereby until the same shall have been delivered to Buyer at the Receipt Point(s).

3.6 Buyer shall be in control and possession of all gas purchased and sold hereunder and responsible for any damage or injury caused thereby after such gas has been delivered to Buyer at the Receipt Point(s).

IV. QUANTITY

4.1 Commencing on the date first written above and continuing throughout the term hereof, Buyer agrees to purchase and receive all of the Dedicated Gas of a quality conforming to this Agreement delivered at the Receipt Point(s) from the well(s) owned or controlled by Seller on the Lands. It is further agreed that neither Buyer nor Seller shall be obligated to purchase and receive or sell and deliver a specific quantity of gas.

 

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4.2 To assist Buyer in maintaining a uniform rate of flow in its processing plant operation, Seller agrees, to the extent reasonable, to regulate its production schedule to achieve a uniform rate of flow can be made to Seller at the Receipt Point(s) described herein.

V. PRICE/TRANSPORTATION AND PAYMENT

5.1 Subject to the other provisions hereof, the price to be paid by Buyer to Seller for all gas purchased and received hereunder shall be based on the total volume of gas received by Buyer at the Receipt Point(s) and thereafter reduced by Seller’s prorata share of fuel for Buyer’s compressor(s) and line loss, if any, in the System and for fuel and shrink attributable to the extraction of liquids in processing. For each Mcf and MMBtu allocated to Seller’s gas, Buyer will pay Seller each month a total price (inclusive of applicable taxes and other adjustments) equal to Eighty Seven Percent (87%) of the net revenue received by Buyer from the sale of all components of Seller’s gas, including the liquid hydrocarbons extracted or recovered in Buyer’s MidMar Plant and the sale of residue gas allocated to Seller for gas processed at the MidMar Plant; and 94.56% of the net revenue received by Buyer from the sale of all components of Seller’s gas, including the liquid hydrocarbons extracted at the Chevron Headlee Plant and the sale of residue gas allocated to Seller for gas processed at the Chevron Headlee Plant.

5.2 Buyer will make payment to Seller for all gas purchased hereunder on or before the fifth (5^th) working day of the second (2^nd) month following the month of production. Seller agrees to make, or cause to be made, payment of all royalties and other payments for interest in production due owners thereof in accordance with the terms of the oil and gas leases and other instruments affecting production from the wells delivering gas to Buyer hereunder. Seller assumes full responsibility and liability for said payments and agrees to indemnify, defend and save Buyer harmless from any and all liability or loss of any kind or character incident to the payment of said royalties.

5.3 Each party hereto shall have the right at all reasonable times to examine the books and records of the other party to the extent necessary to verify the accuracy of any statement, charge, computation, or demand made under or pursuant to this Agreement. Any statement shall be final as to both parties unless questioned within two (2) years after payment thereof has been made.

 

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VI. TAXES

All production, severance, excise, ad valorem and similar taxes imposed or levied by the state or any other governmental agency having jurisdiction on the gas produced, sold or delivered hereunder shall be paid by Seller. In the event Buyer is required by law to remit such tax on behalf of Seller, then the amount thereof shall be deducted from sums due to Seller hereunder. Nothing contained herein shall be construed as applying to any tax imposed on Buyer after title and possession of gas shall have passed to Buyer.

VII. TERM

7.1 This Agreement shall commence with the date first written above and shall continue in full force and effect for a primary term of ten (10) years and year to year thereafter until terminated by either party by giving at least thirty (30) days advance written notice of termination.

VIII. QUALITY

8.1 All gas delivered to Buyer at the Receipt Point(s) shall be merchantable gas which conforms to the gas quality specifications of the Transporting Pipeline except those specifications that apply to water vapor and Btu limitation, and which shall further:

a) be commercially free of dust, gum, gum-forming constituents, which may become separated from the gas during transportation thereof;

b) contain not more than one quarter (1/4) grain of hydrogen sulfide per one hundred (100) cubic feet, as determined by the cadmium sulfate quantitative test, nor more than two (2) grains of total sulfur per one hundred (100) cubic feet;

c) contain not more than two-tenths percent (0.20%) by volume of oxygen;

d) contain not more than two percent (2%) by volume of carbon dioxide content and not more than two percent (2%) by volume of nitrogen;

 

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e) have a heating value of not less than eleven hundred (1,100) Btu (wet basis) per cubic foot;

f) have a temperature of not more than one hundred twenty (120) degrees Fahrenheit.

g) contain not more than four percent (4%) of total inert gases.

8.2 Seller shall have the right to be represented and to participate in all tests of gas delivered hereunder, and to inspect any equipment used in determining the nature of quality of gas.

8.3 Buyer may continue to accept gas which does not meet the quality specifications set forth above provided the residue gas purchaser agrees to accept delivery of the gas at the Delivery Point(s). In the event the Transporting Pipeline will not accept delivery of the gas and neither Buyer nor Seller elects to treat the gas, then such gas shall be released from this Agreement.

IX. MEASUREMENT AND TESTS

The measurement and tests for quality of gas delivered hereunder shall be governed by the following:

9.1 Buyer, at its sole expense, shall install and maintain all measurement facilities located at the Receipt Point(s). Such facilities shall be constructed in compliance with the requirements prescribed in Gas Measurement Committee Report No. 3 of the American Gas Association approved standards of measurement including the appendix thereto, as such report may be amended or revised from time to time.

9.2 The unit of volume for purposes of measurement shall be one (1) standard cubic foot of gas at a temperature base of sixty (60) degrees Fahrenheit and at a pressure base of fourteen and sixty-five hundredths (14.65) psia.

 

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9.3 The arithmetical average of the temperature recorded shall be used to make proper computations of volumes hereunder. Volume computations shall be made as accurately as possible and within the accuracy prescribed by the manufacturer of the equipment used.

9.4 Specific gravity shall be determined through gas analysis calculations or by spot tests made with a standard type of specific gravity instrument which is acceptable to each party hereto.

9.5 The total heating value of the gas shall be determined by Buyer on quarterly intervals by taking samples of the gas at the Receipt Point(s) and having the British thermal unit content per cubic foot determined by means of an approved method of general use in the gas industry.

9.6 Conversion to MMBtu shall be made by multiplying the volume of gas as otherwise determined hereunder by a fraction of the denominator of which is 1,000 and the numerator of which is the gross heat content of the gas per cubic foot in BTU as determined pursuant to Paragraph 9.5 above.

9.7 Tests to determine sulfur, hydrogen sulfide, oxygen, carbon dioxide, nitrogen and water content shall be made by approved standard methods in general use by the gas industry.

9.8 All measuring and testing equipment and materials shall be of standard manufacture and type approved by both parties and shall, with all related equipment and appliances be installed, operated and maintained by Buyer. Seller may, at Seller’s expense, install and operate check measuring and testing equipment, which shall not interfere with the use of Buyer’s equipment.

9.9 The accuracy of Buyer’s measuring and testing equipment shall be verified on semi-annual intervals and at other times upon reasonable request of either party. Tests for quality of the gas may be made at the time of testing the equipment or at other times. Notice of the time and nature of each test shall be given by Buyer hereunder sufficiently in advance to permit convenient arrangement for each party hereto to have a representative to be present. Measuring and testing equipment shall be tested by means and methods in general use in the industry. If after proper notice, either party fails to have a representative present, the results of the tests shall nevertheless be considered accurate until the next tests are made. All tests of measuring equipment shall be made at Buyer’s expense, except that Seller or Buyer shall bear the expense of extra tests made at its request.

 

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9.10 If at any time any of the measuring or testing equipment is found to be out of service or registering inaccurately in any percentage, it shall be adjusted at once to read accurately within the limits prescribed by the manufacturer. If such equipment is out of service or inaccurate by an amount exceeding two percent (2%) at a reading corresponding to the average rate of flow for the period since the last preceding test, the previous readings of such equipment shall be disregarded for any period definitely known or agreed upon, or if not so known or agreed upon, one half (1/2) of the elapsed time since the last test. The volume of gas delivered during such period shall be estimated by (i) using the data reordered by any check measuring equipment if installed and accurately registering, or if not installed or registering accurately, (ii) by correcting the error if the percentage of error is ascertainable by calibration, test or mathematical calculation, or if neither such method is feasible, (iii) by estimating the quantity delivered based upon deliveries under similar conditions during a period when the equipment was registering accurately. No adjustment shall be made for recorded inaccuracies of two percent (2%) or less.

9.11 Either party hereto shall have the right to inspect equipment installed or furnished by the other and the measurement or testing data of the other at all times during business hours; but the reading, calibration and adjustment of such equipment shall be done only by Buyer. Each party shall preserve all original test data, charts and other similar records in such party’s possession for a period of at least two (2) years.

X. FORCE MAJEURE

10.1 The term “Force Majeure”, as employed herein, shall include, without limitation, the following: acts of God and the public enemy, wars, blockades, civil unrest, rebellions, insurrections, riots, lockouts, strikes or any other industrial strife, interruption of civil or public service, epidemics, landslides, lightning, earthquakes, fires, storms, floods, hurricanes, explosions, washouts, freezing of wells or lines of pipe, breakage or failure of wells and equipment, accidents to machinery, wells or lines of pipe, vandalism, inability to obtain or

 

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interruption of third party transportation services, failure of markets, inability to obtain materials, contractors, supplies, permits or labor and any laws, orders, rules, regulations, acts or restraints of any governmental authority, whether or not lawfully made, and any other causes, whether of the kind herein enumerated or otherwise not within the control of the party claiming suspension.

10.2 If either party is rendered unable, wholly or in part, by Force Majeure to perform or comply with any obligations or conditions of this Agreement, upon giving notice in writing and providing reasonably full particulars to the other party, such obligations or conditions, so far as they are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused but for no longer period, and such party shall be relieved of liability and shall suffer no prejudice for failure to perform the same during the period; provided however, that Buyer’s obligation to make payment for gas purchased shall not be suspended. The Force Majeure condition shall be remedied so far as practicable with reasonable dispatch. Settlement of strikes and lockouts shall be wholly within the discretion of the party having the difficulty.

XI. REGULATORY BODIES

11.1 This Agreement shall be subject to all valid applicable Federal, State and local laws, rules and regulations of any governmental body or official having jurisdiction. Both Seller and Buyer shall be entitled to treat all laws, orders, rules and regulations issued by any Federal or State regulatory body as valid and may act in accordance therewith until such time as the same may be invalidated by final judgment in a court of competent jurisdiction.

11.2 If at some future date there is a change in law, rule or regulation, and by such change a governmental certificate or authorization is required or Buyer or Seller is prevented, prohibited or frustrated from carrying out the terms of this Agreement in the manner contemplated hereunder then this Agreement, or as a result of such change in law, rule or regulation this Agreement becomes uneconomic as determined by the impacted party, that party may cancel this Agreement with 90 days prior written notice.

 

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XII. INDEMNIFICATION

Seller and Buyer shall indemnify, defend and save harmless each other from and against any and all loss, damage, injury, liability, and claims for injury to or death of persons (including any employee of Seller or Buyer), or for loss or damage to property (including the property of Buyer or Seller), resulting directly or indirectly from either party’s performance of its respective obligations arising pursuant to this Agreement (including the installation, maintenance and operation of property, equipment and facilities) or any other operations under this Agreement.

XIII. ASSIGNMENTS

Any successor, representative or assignee which shall succeed by purchase, merger or consolidation to the properties, substantially as an entirety, of Seller or Buyer, as the case may be, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement. Either party may assign or pledge this Agreement under the provision of any mortgage, deed of trust, indenture or similar instrument which it has executed or may execute hereafter. Otherwise, neither party shall assign this Agreement or any of its rights, duties or obligations hereunder unless it shall have first obtained the consent in writing of the other party hereto. Such consent shall not be unreasonably withheld.

XIV. NOTICES

Any notice, statement or bill provided for in this Agreement, or any notice which either party may desire to give to the other, shall be in writing and shall be duly delivered when mailed, postage prepaid, by either registered, certified, or first class mail, to the post office address of either of the parties hereto, as the case may be, as follows:

BUYER:

Feagan Gathering Company

130 Spring Park Drive, Ste. 105

P.O. Box 50307

Midland, TX 79710-0307

Telephone No. 432-683-8442

Fax No. 432-683-5442

SELLER:

Windsor Permian LLC

14301 Caliber Drive, Ste. 300

Oklahoma City, OK 73134

Telephone No. 405-242-6104

Fax No. 405-463-6982

 

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XV. MISCELLANEOUS

15.1 No waiver by either party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be construed as a waiver of any other default or defaults, whether of a like or of a different character.

15.2 The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Texas.

15.3 If at any time and from time to time Buyer determines that the purchase of gas hereunder is not profitable to Buyer, then Buyer will notify Seller in writing and supply information supporting Buyer’s determination. Buyer will state a price or fee which would enable Buyer to continue purchasing Seller’s gas. Seller shall have thirty (30) days after receipt of Buyer’s notice in which to advise Buyer in writing if Seller elects to reject the price or fee stated. If Buyer does not receive Seller’s notice of rejection within thirty (30) days, then Buyer’s stated price/fee shall be effective as of the date of Buyer’s notice under this paragraph. If Buyer’s stated price/fee is rejected by Seller, then Seller may terminate this Agreement by giving Buyer thirty (30) days written notice. Buyer is specifically prohibited from invoking this provision 15.3 until such time as MidMar Plant is processing 10,000 Mcfd for a period of three consecutive months or two years from the in service date of MidMar Plant, whichever is soonest.

15.4 This Agreement constitutes the entire agreement between the parties pertaining to the subject matter hereof and understandings, whether oral or written which the parties may have in connection herewith may not be modified except by written agreement of the parties.

15.5 Each party shall do all necessary acts and make, execute and deliver such written instruments as shall from time to time be reasonably required to carry out the terms of this Agreement.

15.6 If any provision of this Agreement shall be held invalid, illegal or unenforceable to any extent and for any reason by a court of competent jurisdiction the remainder of this Agreement shall not be affected thereby and shall be enforceable to the full extent permitted by law.

 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the day and year first written above.

 

“Buyer”						“Seller”
Feagan Gathering Company						Windsor Permian LLC
By:		/s/ Mike Feagan				By:		/s/ Steven E. West
Title:		President				Title:		Managing Director

 

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EXHIBIT “A”

Attached to and made a part of that certain Gas Purchase Agreement, dated May 1, 2009.

Between Feagan Gathering Company

And Windsor Permian, LLC.

 

Lease Name		Acreage Description		County & State
Spanish Trail		Block 40, T1S, T&P RR Survey Sec. 39: S/2 Sec. 40, 41, 42, 43, 44 & 45: All		Midland, TX
		Block 40, T2S, T&P RR Survey Sec. 5, 6 & 7: All Sec. 8: N/2 & S/2 lying north of RR ROW.		Midland, TX
		Block 41, T1S, T&P RR Survey Sec. 25, 26 & 38: All Sec. 36: E/2		Midland/Ector, TX
Hurt Lease		Block 42, T1S, T&P RR Survey Sec. 2, 4, 9, 10, 11 & 13: All		Ector, TX
University Lease		University Lands, Block 1 Sec. 1: S/2 Sec. 2, 11 & 12: All Sec. 13: NW/4		Andrews, TX
		University Lands, Block 2 Sec. 1 & 6: N/2 & SW/4 Sec. 2, 3, 4, 7 & 8: All Sec. 5: W/2 & SE/4 Sec. 9: E/2 & N/2 NW/4

Exhibit 10.21

AMENDMENT

TO

GAS PURCHASE AGREEMENT

THIS AMENDMENT to that certain Gas Purchase Agreement, dated May 1, 2009 (the “Agreement”) is made and entered into as of July 1, 2011, by and between MidMar Gas LLC, (successor to Feagan Gathering Company insofar as the Agreement is concerned) (“Buyer”) and Windsor Permian LLC (“Seller”).

Recitals

WHEREAS, Buyer and Seller are parties to the Agreement covering the purchase and sale of gas from wells located on the acreage described in Exhibit “A” to the Agreement.

WHEREAS, in consideration of the mutual benefits derived by the parties hereto Buyer and Seller agree as follows:

Effective August 1, 2011, Article III., Receipt Point(s), Delivery Point(s) and Delivery Pressure, of the Agreement is hereby amended to include the following provision as Section 3.7:

“Seller shall retain title to Seller’s gas and all of its components following delivery of such gas to Buyer at the Receipt Point(s) as defined in Article III herein. Title to the gas, recovered natural gas liquids and residue gas and all other components shall pass and vest in Buyer at (a) the tailgate of Buyer’s plant where Seller’s gas is processed or (b) such other Delivery Point(s) utilized by Buyer from time to time in the sale of gas attributable to Seller.”

Except as herein amended, the Agreement shall remain in full force and effect as previously written.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the day and year first written above.

 

“Buyer”						“Seller”
MidMar Gas LLC						Windsor Permian LLC
By:		/s/ Mike Feagan				By:		/s/ Travis D. Stice
Title:		Vice President				Title:		President & COO

Exhibit 10.22

AMENDMENT

TO

GAS PURCHASE AGREEMENT

THIS AMENDMENT to that certain Gas Purchase Agreement, dated May 1, 2009, as amended, is made and entered into this 11th day of January, 2012, by and between MidMar Gas LLC (successor to Feagan Gathering Company insofar as this Agreement is concerned) (“Buyer”) and Windsor Permian LLC (“Seller”).

RECITALS

WHEREAS, Buyer and Seller are parties to that certain Gas Purchase Agreement dated May 1, 2009, as amended, (the “Agreement”) covering the purchase and sale of gas produced from wells located on the acreage described in Exhibit “A” to the Agreement, and

WHEREAS, Buyer and Seller would like to release from the Agreement a portion of the gas committed under the Agreement in order for Seller to market such gas to a purchaser other than Buyer.

NOW, THEREFORE, for and in consideration of mutual covenants and conditions contained herein and other good and valuable consideration, the parties hereto mutually agree as follows:

“Effective March 1, 2012, all gas produced from wells located on the acreage described below is hereby released from the Agreement on a month-to-month basis subject to Buyer’s express right to re-establish the purchase of such gas in accordance with the Agreement at any time effective on or after January 1, 2017 by providing Seller at least thirty (30) days written notice.”

 

Lease Name		Acreage Description		County, State
Windsor Hurt Lease (WHL)		Sections 2, 4, 9, 10 and 11 Block 42, Township 1 South, T&P RR Co. Survey		Ector, Texas

Except as herein amended, the Agreement shall remain in full force and effect as previously written.

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the day and year first written above.

 

“Buyer”						“Seller”
MidMar Gas LLC						Windsor Permian LLC
By:		/s/ Mike Feagan				By:		/s/ Travis D. Stice
Title:		Vice President				Title:		President & CEO

 

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued (i) our report dated March 23, 2012, with respect to the consolidated financial statements of Windsor Permian LLC, (ii) our report dated May 1, 2012, with respect to the financial statements of Windsor UT LLC, and (iii) our report dated April 24, 2012, with respect to the statements of revenues and direct operating expenses of working and revenue interests of certain oil and gas properties owned by Gulfport Energy Corporation, contained in the Registration Statement and Prospectus of Diamondback Energy, Inc. We consent to the use of the aforementioned reports in the Registration Statement and Prospectus, and to the use of our name as it appears under the caption “Experts”.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

May 7, 2012

Exhibit 23.2

CONSENT OF PINNACLE ENERGY SERVICES, LLC

We have issued our report letters dated January 25, 2011 and January 6, 2010 for the years ended December 31, 2010 and 2009, respectively, on estimates of proved reserves and future net cash flows of certain oil and natural gas properties located in the Permian Basin of West Texas of Windsor Permian LLC, successor in interest to Windsor Energy Group, LLC. As independent oil and gas consultants, we hereby consent to the use and inclusion of information from the aforementioned report letters in this Amendment to the Registration Statement on Form S-1/A. We hereby also consent to the references to our firm and to the use of our name, as it appears under the caption “Experts,” in this Amendment to the Registration Statement on Form S-1/A.

 

May 5, 2012

Oklahoma City, Oklahoma

Exhibit 23.3

CONSENT OF RYDER SCOTT COMPANY, L.P.

We hereby consent to the references to our firm in this Amendment to the Registration Statement on Form S-1/A for Diamondback Energy, Inc. and to the use of information from, and the inclusion of, in this Amendment our reports dated January 20, 2012, January 20, 2012 and January 13, 2012 with respect to the estimates of reserves, future production and income attributable to certain leasehold interests of Windsor Permian LLC, Windsor UT, LLC and Gulfport Energy Corporation, respectively, in properties located in the Permian Basin in West Texas, in each case as of December 31, 2011. We further consent to the reference to our firm under the heading “Experts” in this Amendment and related prospectus.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

May 4, 2012

Houston, Texas