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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



☒	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019



☐	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-35700

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)



DE		45-4502447
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)

500 West Texas
Suite 1200
Midland,	TX	79701
(Address of principal executive offices)		(Zip code)

(Registrant Telephone Number, Including Area Code): (432) 221-7400



	Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class		Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share		FANG	The Nasdaq Stock Market LLC
			(NASDAQ Global Select Market)
	Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2019 was approximately $15.9 billion.

As of February 14, 2020, 158,284,486 shares of the registrant’s common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K

DIAMONDBACK ENERGY, INC.

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2019

TABLE OF CONTENTS



	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	v
Cautionary Statement Regarding Forward-Looking Statements	vi

PART I
Items 1 and 2. Business and Properties	1
Item 1A. Risk Factors	26
Item 1B. Unresolved Staff Comments	53
Item 3. Legal Proceedings	53
Item 4. Mine Safety Disclosures	53

PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	54
Item 6. Selected Financial Data	55
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	57
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	80
Item 8. Financial Statements and Supplementary Data	81
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	81
Item 9A. Controls and Procedures	82
Item 9B. Other Information	85

PART III
Item 10. Directors, Executive Officers and Corporate Governance	86
Item 11. Executive Compensation	86
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	86
Item 13. Certain Relationships and Related Transactions, and Director Independence	86
Item 14. Principal Accountant Fees and Services	87

PART IV
Item 15. Exhibits and Financial Statement Schedules	87
Item 16. Form 10-K Summary	91
Signatures	S-1

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms used in this report:



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	A large depression on the earth’s surface in which sediments accumulate.
Bbl	Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
Bbls/d	Barrels per day.
BOE	Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d	Barrels of oil equivalent per day.
Brent	Brent sweet light crude oil.
British Thermal Unit or BTU	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
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 that is primarily natural gas.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Developed acreage	Acreage assignable to productive wells.
Development costs	Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
Differential	An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry hole or dry well	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.
Estimated Ultimate Recovery or EUR	Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploitation	A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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.
Horizontal wells	Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mb/d	Thousand barrels per day.
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/d	Thousand cubic feet of natural gas per day.
Mineral interests	The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu	Million British Thermal Units.

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MMcf	Million cubic feet of natural gas.
Net acres or net wells	The sum of the fractional working interest owned in gross acres.
Net revenue interest	An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
Net royalty acres	Gross acreage multiplied by the average royalty interest.
Oil and natural gas properties	Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator	The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
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	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	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.
Reserves	Reserves are estimated remaining quantities of oil and natural 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 natural gas or related substances to the market and all permits and financing required to implement the project. 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).
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.
Resource 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.
Royalty interest	An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Tight formation	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 economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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Working interest	An 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.
WTI	West Texas Intermediate.
WTI MEH	West Texas Intermediate Magellan East Houston.
WTL	West Texas Light

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report.



ASU	Accounting Standards Update
Company	Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173).
EPA	U.S. Environmental Protection Agency.
Equity Plan	The Company’s Equity Incentive Plan.
Exchange Act	The Securities Exchange Act of 1934, as amended.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission.
GAAP	Accounting principles generally accepted in the United States.
2024 Indenture	The indenture relating to the 2024 Senior Notes, dated as of October 28, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2025 Indenture	The indenture relating to the 2025 Senior Notes, dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
December 2019 Notes Indenture	The indenture relating to the December 2019 Notes dated as of December 5, 2019, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
NYMEX	New York Mercantile Exchange.
OSHA	Federal Occupational Safety and Health Act.
Rattler	Rattler Midstream LP, a Delaware limited partnership.
Rattler’s general partner	Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly-owned subsidiary of the Company.
Rattler LLC	Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler LTIP	Rattler Midstream LP Long-Term Incentive Plan.
Rattler Offering	Rattler’s initial public offering.
Rattler’s Partnership Agreement	The first amended and restated agreement of limited partnership, dated May 28, 2019.
Ryder Scott	Ryder Scott Company, L.P.
SEC	Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
2024 Senior Notes	The Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $1,250 million.
2025 Senior Notes	The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
Senior Notes	The 2024 Senior Notes, the 2025 Senior Notes and the Series of Senior Notes
December 2019 Notes	The Company’s 2.875% senior unsecured notes due 2024 in the aggregate principal amount of $1.0 billion, the Company’s 3.250% senior unsecured notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% senior unsecured notes due 2029 in the aggregate principal amount of $1.2 billion.
Viper	Viper Energy Partners LP, a Delaware limited partnership.
Viper’s general partner	Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLC	Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Viper LTIP	Viper Energy Partners LP Long Term Incentive Plan.
Viper Offering	Viper’s initial public offering.
Viper’s Partnership Agreement	The second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018.
Wells Fargo	Wells Fargo Bank, National Association.
Wexford	Wexford Capital LP

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this Annual Report on Form 10–K, including under Part I, Item 1A. “Risk Factors” in this report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:


•	business strategy;


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


•	oil and natural gas reserves;


•	competition in the oil and natural gas industry;


•	acquisitions;


•	our recently completed drop-down transaction with our subsidiary Viper Energy Partners LP, or Viper;


•	identified drilling locations;


•	ability to obtain permits and governmental approvals;


•	technology;


•	financial strategy;


•	realized oil and natural gas prices and effects of hedging arrangements;


•	levels of production;


•	the impact of reduced drilling activity;


•	regional supply and demand factors, delays or interruptions of production;


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


•	future operating results;


•	conditions in the capital markets and our ability to obtain capital on favorable terms or at all;


•	general economic business or industry conditions;


•	capital expenditure plans; and


•	other plans, objectives, expectations and intentions.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

vii

PART I

Except as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,” or “the Company”. This report includes certain terms commonly used in the oil and gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”

ITEM 1. BUSINESS AND PROPERTIES

Overview

We are an independent oil and natural gas company 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 in the Permian Basin. At December 31, 2019, our total acreage position in the Permian Basin was approximately 455,378 gross (382,337 net) acres, which consisted primarily of approximately 218,138 gross (195,461 net) acres in the Midland Basin and approximately 196,171 gross (155,296 net) acres in the Delaware Basin. In addition, our publicly traded subsidiary Viper Energy Partners LP, which we refer to as Viper, owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 50% of these net royalty acres are operated by us. We own Viper Energy Partners GP LLC, the general partner of Viper, which we refer to as Viper’s general partner, and we own approximately 58% of the limited partner interest in Viper. Further, our publicly traded subsidiary Rattler Midstream Partners LP, which we refer to as Rattler, is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. We own Rattler Midstream GP LLC, the general partner of Rattler, which we refer to as Rattler’s general partner, and we own approximately 71% of the limited partner interest in Rattler. As of December 31, 2019, Rattler owned and operated 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas. To facilitate the transportation of produced water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.

Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcamp and Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. The Permian Basin 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.

As of December 31, 2019, our estimated proved oil and natural gas reserves were 1,127,575 MBOE (which includes estimated reserves of 88,946 MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 67% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 477 gross (434 net) horizontal well locations in which we have a working interest, and 22 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2019, our estimated proved reserves were approximately 63% oil, 20% natural gas liquids and 17% natural gas.

Based on our evaluation of applicable geologic and engineering data, we currently have approximately 12,310 gross (8,141 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

Significant 2019 Transactions

Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen

On May 23, 2019, we completed our divestiture of 6,589 net acres of certain non-core Permian assets, which we acquired in our November 2018 merger with Energen Corporation, which we refer to as the Energen merger, for an aggregate sale price of $37 million.

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On July 1, 2019, we completed our divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which we acquired in the Energen merger, for an aggregate sale price of $285 million.

Drop-Down

On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down. The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.

Rattler’s Initial Public Offering

In May 2019, Rattler completed its initial public offering, which we refer to as the Rattler Offering, of an aggregate 43,700,000 common units at a price to the public of $17.50 per share, which common units are traded on the Nasdaq Global Select Market under the symbol “RTLR.” Rattler received aggregate net proceeds of approximately $720 million from the sale of these common units, after deducting the underwriting discount and offering expenses.

Our Business Strategy

Our business strategy is to continue to profitably grow our business through the following:


•	Grow production and reserves by developing our oil-rich resource base. We intend to 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.

•

Focus on increasing hydrocarbon recovery through horizontal development of stacked horizons. We have been developing multiple pay intervals in the Permian Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphic column. Our initial horizontal wells were completed in 2012, and since then we have been an active horizontal driller in the basin. We believe that our significant experience drilling, completing and operating horizontal wells will allow us to efficiently develop our remaining inventory and ultimately target other horizons that have limited development to date. The following table presents horizontal wells in which we have an interest in as of December 31, 2019:



Basin	Number of Horizontal Wells
Midland	1,125
Delaware	645
Total⁽¹⁾	1,770

(1) Of these 1,770 total horizontal wells, we are the operator of 1,489 producing wells and have a non-operated working interest in 281 additional wells.

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The following table presents the average number of days in which we were able to drill our horizontal wells to total depth specified below during the year ended December 31, 2019:



	Average Days to Total Depth
Midland Basin
7,500 foot lateral	14
10,000 foot lateral	15
13,000 foot lateral	17
Delaware Basin
7,500 foot lateral	20
10,000 foot lateral	25
13,000 foot lateral	27

Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.

•

Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to 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.

•

Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position 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 97% of our acreage. This operational control allows us to manage more efficiently 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 84% working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.

•

Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. 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 regularly review acquisition opportunities and intend 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, 2019, our borrowing base was set at $2.0 billion and we had $1.99 billion available for borrowing. As of December 31, 2019, Viper LLC had $97 million in outstanding borrowings, and $678 million available for borrowing, under its revolving credit facility. As of December 31, 2019, Rattler LLC had $424 million in outstanding borrowings, and $176 million available for borrowing, under its revolving credit facility.

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. The majority of our current properties are well positioned in the core of the Permian Basin. Our production for the year ended December 31, 2019 was approximately 66% oil, 18% natural gas liquids and 16% natural gas. As of December 31, 2019, our

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estimated net proved reserves were comprised of approximately 63% oil, 20% natural gas liquids and 17% 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 our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 12,310 gross (8,141 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately 7,975 feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. In addition, we have approximately 3,413 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions.

The following table presents the number of identified economic potential horizontal drilling locations by basin:



	Number of Identified Economic Potential Horizontal Drilling Locations
Midland Basin
Lower Spraberry⁽¹⁾	1,231
Middle Spraberry⁽²⁾	1,151
Wolfcamp A⁽³⁾	1,205
Wolfcamp B⁽⁴⁾	1,213
Other	2,237
Total Midland Basin	7,037
Delaware Basin
2nd Bone Springs⁽⁵⁾	957
3rd Bone Springs⁽⁵⁾	1,177
Wolfcamp A⁽⁶⁾	944
Wolfcamp B⁽⁶⁾	1,050
Other	1,145
Total Delaware Basin	5,273
Total	12,310


(1)	Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties.


(2)	Our current location count is based on 660 foot spacing in Midland, Martin and northeast Andrews counties, depending on the prospect area and 880 foot spacing in all other counties.


(3)	Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties.


(4)	Our current location count in based on 660 foot to 880 foot spacing in Midland, Martin, northeast Andrews, Howard and Glasscock counties, depending on the prospect area and 880 foot spacing in all other counties.


(5)	Our current location count is based on 880 foot to 1,320 foot spacing.


(6)	Our current location count is based on 880 foot to 1,056 foot spacing.

•

Experienced, incentivized and proven management team. Our executive team has an average of over 25 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 in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

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Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longest operating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin 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 97% 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 processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

•

Access to Midstream Infrastructure and Gathering and Transportation Pipelines. Through our publicly traded subsidiary Rattler, we have secured access to midstream infrastructure and crude oil gathering and transportation pipelines tailored to our expected production growth ramp in order to allow us the operational flexibility to execute on our growth plan. Rattler is the primary provider of midstream services to us with an acreage dedication that spans a total of approximately 397,000 gross acres across all of Rattler’s service lines and over the core of the Midland and Delaware Basins.

Our Properties

Location and Land

Our total acreage position in the Permian Basin was approximately 455,378 gross (382,337 net) acres, which consisted primarily of approximately 218,138 gross (195,461 net) acres in the Midland Basin and approximately 196,171 gross (155,296 net) acres in the Delaware Basin at December 31, 2019. We are the operator of approximately 97% of this Permian Basin acreage. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 814,224 gross acres and 24,304 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 50% of these net royalty acres are operated by us.

Further, our subsidiary Rattler is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. As of December 31, 2019, Rattler owned and operated 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays our seven core Midland and Delaware Basin development areas. To facilitate the transportation of water and hydrocarbon volumes away from the producing wellhead to ensuring the efficient operations of a crude oil or natural gas well, Rattler’s midstream infrastructure includes a network of gathering pipelines that collect and transport crude oil, natural gas and produced water from our operations in the Midland and Delaware Basins.

As of December 31, 2019, Rattler also owned (i) a 10% equity interest in EPIC Crude Holdings LP, which is building a long-haul crude oil pipeline from the Permian Basin and the Eagle Ford Shale to Corpus Christi, Texas that, upon completion, will be capable of transporting approximately 590,000 Bbl/d and, with installation of additional pumps and storage, up to approximately 900,000 Bbl/d, which we refer to as the EPIC pipeline; (ii) a 10% equity interest in Gray Oak Pipeline, LLC, which is building a long-haul crude oil pipeline that, upon completion, will be capable for transporting 900,000 Bbl/d from the Permian Basin and the Eagle Ford Shale to points alongside the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas, which we refer to as the Gray Oak pipeline; (iii) a 4% equity interest in Wink to Webster Pipeline LLC, which is developing a crude oil pipeline that, upon completion, will be capable of transporting approximately 1,000,000 Bbl/d from origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations, (iv) a 60% equity interest in OMOG JV LLC, a newly formed joint venture entity that acquired Reliance Midstream LLC, which operates over 230 miles of crude oil gathering and regional transportation pipelines and approximately 200,000 barrels of crude oil storage in Midland, Martin, Andrews and Ector Counties, Texas, and (v) a 50% equity interest in Amarillo Rattler LLC, which will operate the Yellow Rose gas gathering and processing system with estimated total capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. Each of the Epic and Gray Oak pipelines began interim operations in the second half of 2019, and we expect both to begin full commercial operations in the second quarter of 2020. The Wink to Webster project is expected to begin commercial operations in first half of 2021. We anticipate that the Yellow Rose system will commence full commercial operations in the middle of 2021.

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.

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Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, 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 a portion 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. Since then we and most other operators are almost exclusively drilling horizontal wells in the development of unconventional reservoirs in the Permian Basin. As of December 31, 2019, we held working interests in 2,656 gross (2,202 net) producing wells and only royalty interests in 4,161 additional wells.

Geology

The Greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence of the Marathon Uplift and Ancestral Rockies. It is one of the most productive sedimentary basins in the U.S., with established oil and gas production from several stacked reservoirs of varying age ranges, most notably Permian aged sediments. In particular, the Permian aged Wolfcamp and Spraberry/Bone Spring Formations have been heavily targeted for several decades. First, through vertical comingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of Wolfcamp and Spraberry/Bone Spring Formations, the area of the present-day Permian Basin was a continuous sedimentary feature called the Tabosa Basin. During this time, Ordovician, Silurian, Devonian and Mississippian sediments were laid down in a primarily open marine, shelf setting. However, some time frames saw more restrictive settings that were conducive to the deposition of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett/Meramec. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.

The Spraberry/Bone Spring was deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and fine-grained pelagic sediments, which were also deposited in a basinal setting. The best carbonate reservoirs within the Wolfcamp and Spraberry/Bone Spring are generally found in close proximity to the Central Basin Platform, while mudstone reservoirs thicken basin-ward, away from the Central Basin Platform. The mudstone within these reservoirs is organically rich, which when buried to sufficient depth for thermal maturation, became the source of the hydrocarbons found both within the mudstones themselves and in the interbedded conventional clastic and carbonate reservoirs. Due to this complexity, the Wolfcamp and Spraberry/Bone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional and conventional reservoirs.

We have successfully developed several hybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp and Barnett/Meramec formations since we began horizontal drilling in 2012. The mudstones and some clastics exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage of hydrocarbons in these targets.

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We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas. Our extensive geophysical database currently includes approximately 3,413 square miles of 3-D data. This data will continue to be utilized in the development of our horizontal drilling program and identification of additional resource to be exploited.

Production Status

During the year ended December 31, 2019, net production from our Permian Basin acreage was 103,285 MBOE, or an average of 282,972 BOE/d, of which approximately 66% was oil, 18% was natural gas liquids and 16% was natural gas.

Facilities

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

Our publicly traded subsidiary Rattler owns the Fasken Center which has over 421,000 net rentable square feet within its two office towers and associated assets in Midland, Texas. We, Viper and Rattler are headquartered at the Fasken Center. We and unrelated third parties lease office space within the Fasken Center from Rattler under long-term lease agreements.

We and our subsidiaries also own field offices and related facilities in Midland and Reeves Counties, Texas. We believe that these facilities are adequate for our current operations.

Recent and Future Activity

During 2020, we expect to complete an estimated 320 to 360 gross (288 to 324 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2020 for drilling and infrastructure will be between $2.8 billion and $3.0 billion, consisting of $2.45 billion to $2.6 billion for horizontal drilling and completions including non-operated activity, $200 million to $225 million for midstream investments, excluding joint venture investments, and $150 million to $175 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. During the year ended December 31, 2019, we drilled 330 gross (296 net) and completed 317 gross (289 net) operated horizontal wells. During the year ended December 31, 2019, our capital expenditures for drilling, completing and equipping wells were $2.6 billion. In addition, we spent $364 million for oil and gas midstream and infrastructure and $776 million for leasehold and mineral rights acquisitions.

We are operating 23 drilling rigs now including two rigs drilling produced water disposal wells and currently intend to operate between 20 and 23 rigs on average in 2020. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions.

With our current development plan, we expect to continue our strong PUD conversion ratio in 2020 by converting an estimated 35% of our PUDs to a proved developed category, and develop approximately 66% of the consolidated 2019 year-end PUD reserves by the end of 2021.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2019, 2018 and 2017 were prepared by Ryder Scott with respect to our assets and those of Viper. Ryder Scott 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 of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas that, 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 proved

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reserves as of December 31, 2019 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 producing 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 reports 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 Executive Vice President–Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Executive 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 20 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.

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 Executive Vice President–Reservoir Engineering or under his direct supervision;


•	review by our Executive 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 Executive Vice President–Reservoir Engineering to our Chief Executive Officer;


•	verification of property ownership by our land department; and


•	no employee’s compensation is tied to the amount of reserves booked.

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The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2019, 2018 and 2017 (including those attributable to Viper), based on the reserve reports prepared by Ryder Scott. Each reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States.



	As of December 31,
	2019		2018		2017
Estimated proved developed reserves:
Oil (MBbls)	457,083		403,051		141,246
Natural gas (MMcf)	824,760		705,084		190,740
Natural gas liquids (MBbls)	165,173		125,509		35,412
Total (MBOE)	759,716		646,074		208,447
Estimated proved undeveloped reserves:
Oil (MBbls)	253,820		223,885		91,935
Natural gas (MMcf)	294,051		343,565		94,629
Natural gas liquids (MBbls)	65,030		64,782		19,198
Total (MBOE)	367,859		345,928		126,905
Estimated Net Proved Reserves:
Oil (MBbls)	710,903		626,936		233,181
Natural gas (MMcf)	1,118,811		1,048,649		285,369
Natural gas liquids (MBbls)	230,203		190,291		54,609
Total (MBOE)⁽¹⁾	1,127,575		992,001		335,352
Percent proved developed	67	%	65	%	62	%

(1)

Estimates of reserves as of December 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017, respectively, in accordance with 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 Item 1A.“Risk Factors.” 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.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2019, our proved undeveloped reserves totaled 253,820 MBbls of oil, 294,051 MMcf of natural gas and 65,030 MBbls of natural gas liquids, for a total of 367,859 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

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The following table includes the changes in PUD reserves for 2019:



	(MBOE)
Beginning proved undeveloped reserves at December 31, 2018	345,928
Undeveloped reserves transferred to developed	(120,920	)
Revisions	(77,519	)
Net purchases	4,542
Divestitures	(5,672	)
Extensions and discoveries	221,500
Ending proved undeveloped reserves at December 31, 2019	367,859

The increase in proved undeveloped reserves was primarily attributable to extensions of 213,909 MBOE from 291 gross (262 net) wells in which we have a working interest and 7,591 MBOE from 97 gross wells in which Viper owns royalty interests. Of the 291 gross working interest wells, 64 were in the Delaware Basin. Transfers of 120,920 MBOE were the result of drilling or participating in 135 gross (119 net) horizontal wells in which we have a working interest and 79 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 75 of the 79 gross Viper wells. Downward revisions of 77,519 MBOE resulted from 67,114 MBOE of PUD downgrades due to refinement of the PUD inventory following the Energen merger. These downgrades were offset with extensions. The remaining 10,405 MOE of downward revisions were mostly from lower benchmark commodity prices.

Costs incurred relating to the development of PUDs were approximately $956 million during 2019. Estimated future development costs relating to the development of PUDs are projected to be approximately $1.2 billion in 2020, $721 million in 2021, $641 million in 2022 and $576 million in 2023. Since our current 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.

As of December 31, 2019, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

As of December 31, 2019, none of our total proved reserves were classified as proved developed non-producing.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids by basin for each of the periods indicated:



	Year Ended December 31, 2019				Year Ended December 31, 2018
	Midland Basin	Delaware Basin	Other⁽¹⁾	Total	Midland Basin	Delaware Basin	Other⁽²⁾	Total
	(in thousands)
Production Data:
Oil (MBbls)	41,156	25,951	1,411	68,518	24,698	9,288	381	34,367
Natural gas (MMcf)	48,109	48,447	1,057	97,613	21,674	12,416	579	34,669
Natural gas liquids (MBbls)	10,485	7,826	187	18,498	5,493	1,866	106	7,465
Total (MBoe)	59,659	41,852	1,774	103,285	33,803	13,223	584	47,610


(1)	Includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.


(2)	Includes the Eagle Ford Shale.

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	December 31, 2017
	Midland Basin	Delaware Basin	Other⁽¹⁾	Total
	(in thousands)
Production Data:
Oil (MBbls)	17,553	3,865	—	21,418
Natural gas (MMcf)	15,893	4,761	6	20,660
Natural gas liquids (MBbls)	3,673	383	—	4,056
Total (MBoe)	23,875	5,042	1	28,917


(1)	Includes the Eagle Ford Shale.

The following table sets forth certain price and cost information for each of the periods indicated:



	Year Ended December 31,
	2019		2018		2017
Average Prices:
Oil ($ per Bbl)	$	51.87	$	54.66	$	48.75
Natural gas ($ per Mcf)	0.68		1.76		2.53
Natural gas liquids ($ per Bbl)	14.42		25.47		22.20
Combined ($ per BOE)	37.63		44.73		41.02
Oil, hedged ($ per Bbl)⁽¹⁾	51.96		51.20		48.94
Natural gas, hedged ($ per MMbtu)⁽¹⁾	0.86		1.72		2.65
Natural gas liquids, hedged ($ per Bbl)⁽¹⁾	15.20		25.46		—
Average price, hedged ($ per BOE)⁽¹⁾	38.00		42.20		41.26

Average Costs per BOE:
Lease operating expense	$	4.74	$	4.31	$	4.38
Production and ad valorem taxes	2.40		2.79		2.54
Gathering and transportation expense	0.86		0.55		0.44
General and administrative - cash component	0.54		0.79		0.80
Total operating expense - cash	$	8.54	$	8.44	$	8.16

General and administrative - non-cash component	$	0.46	$	0.57	$	0.88
Depreciation, depletion and amortization	14.01		13.09		11.30
Interest expense, net	1.66		1.83		1.40
Merger and integration expense	—		0.77		—
Total expenses	$	16.13	$	16.26	$	13.58


(1)	Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

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Wells Drilled and Completed in 2019

The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2019:



	Year Ended December 31, 2019
	Drilled		Completed
Area	Gross	Net	Gross	Net
Midland Basin	171	154	178	163
Delaware Basin	159	142	139	126
Total	330	296	317	289

As of December 31, 2019, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	833	768	1,004	913	1,837	1,681
Delaware Basin	—	—	485	453	485	453
Other	3	3	—	—	3	3
Total	836	771	1,489	1,366	2,325	2,137

Productive Wells

As of December 31, 2019, we owned an average unweighted 83% working interest in 2,656 gross (2,202 net) productive wells and an average 3.1% royalty interest in 4,161 additional wells. Through our subsidiary Viper, we own an average unweighted 3.4% royalty or mineral interest in 5,807 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.

The following table sets forth information regarding productive wells by basin as of December 31, 2019:



	Gross Wells	Net Wells
Midland Basin	1,993	1,717
Delaware Basin	660	482
Other	3	3
Total productive wells	2,656	2,202

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Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated by basin. Each of these wells was drilled in the Permian Basin of West Texas. 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, 2019
	Midland Basin		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
Development:
Productive	75	68	31	28	106	96
Dry	—	—	—	—	—	—
Exploratory:
Productive	96	86	128	114	224	200
Dry	—	—	—	—	—	—
Total:
Productive	171	154	159	142	330	296
Dry	—	—	—	—	—	—



	Year Ended December 31, 2018
	Midland Basin		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
Development:
Productive	67	58	21	20	88	78
Dry	—	—	—	—	—	—
Exploratory:
Productive	50	43	38	35	88	78
Dry	—	—	—	—	—	—
Total:
Productive	117	101	59	55	176	156
Dry	—	—	—	—	—	—



	Year Ended December 31, 2017
	Midland Basin		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
Development:
Productive	26	22	1	1	27	23
Dry	—	—	—	—	—	—
Exploratory:
Productive	93	67	19	17	112	84
Dry	—	—	—	—	—	—
Total:
Productive	119	89	20	18	139	107
Dry	—	—	—	—	—	—

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Acreage

The following table sets forth information as of December 31, 2019 relating to our leasehold acreage:



	Developed Acreage⁽¹⁾		Undeveloped Acreage⁽²⁾		Total Acreage⁽³⁾
Basin	Gross⁽⁴⁾	Net⁽⁵⁾	Gross⁽⁴⁾	Net⁽⁵⁾	Gross⁽⁴⁾	Net⁽⁵⁾
Conventional Permian	1,278	1,154	1,507	1,401	2,785	2,555
Delaware	92,408	75,815	103,763	79,481	196,171	155,296
Exploration	160	160	38,124	28,865	38,284	29,025
Midland	135,792	123,159	82,346	72,302	218,138	195,461
Total	229,638	200,288	225,740	182,049	455,378	382,337

(1)

Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.


(2)	<