Company Quick10K Filing
Diamondback Energy
Price89.99 EPS7
Shares164 P/E14
MCap14,800 P/FCF14
Net Debt4,661 EBIT1,350
TEV19,461 TEV/EBIT14
TTM 2019-09-30, in MM, except price, ratios
10-K 2020-12-31 Filed 2021-02-25
10-Q 2020-09-30 Filed 2020-11-05
10-Q 2020-06-30 Filed 2020-08-10
10-Q 2020-03-31 Filed 2020-05-08
10-K 2019-12-31 Filed 2020-02-27
10-Q 2019-09-30 Filed 2019-11-06
10-Q 2019-06-30 Filed 2019-08-09
10-Q 2019-03-31 Filed 2019-05-10
10-K 2018-12-31 Filed 2019-02-25
10-Q 2018-09-30 Filed 2018-11-07
10-Q 2018-06-30 Filed 2018-08-09
10-Q 2018-03-31 Filed 2018-05-10
10-K 2017-12-31 Filed 2018-02-15
10-Q 2017-09-30 Filed 2017-11-07
10-Q 2017-06-30 Filed 2017-08-02
10-Q 2017-03-31 Filed 2017-05-04
10-K 2016-12-31 Filed 2017-02-15
10-Q 2016-09-30 Filed 2016-11-08
10-Q 2016-06-30 Filed 2016-08-09
10-Q 2016-03-31 Filed 2016-05-05
10-K 2015-12-31 Filed 2016-02-19
10-Q 2015-09-30 Filed 2015-11-06
10-Q 2015-06-30 Filed 2015-08-10
10-Q 2015-03-31 Filed 2015-05-07
10-K 2014-12-31 Filed 2015-02-20
10-Q 2014-09-30 Filed 2014-11-06
10-Q 2014-06-30 Filed 2014-08-07
10-Q 2014-03-31 Filed 2014-05-09
10-K 2013-12-31 Filed 2014-02-19
10-Q 2013-09-30 Filed 2013-11-05
10-Q 2013-06-30 Filed 2013-08-08
10-Q 2013-03-31 Filed 2013-05-09
10-K 2012-12-31 Filed 2013-03-01
10-Q 2012-09-30 Filed 2012-11-16
8-K 2021-02-22 Earnings, Exhibits
8-K 2020-12-18 Enter Agreement, Sale of Shares, Regulation FD, Other Events, Exhibits
8-K 2020-11-02
8-K 2020-08-03
8-K 2020-06-03
8-K 2020-05-26
8-K 2020-05-18
8-K 2020-05-18
8-K 2020-05-04
8-K 2020-04-03
8-K 2020-02-18
8-K 2019-12-05
8-K 2019-11-20
8-K 2019-11-18
8-K 2019-11-13
8-K 2019-11-05
8-K 2019-09-30
8-K 2019-08-28
8-K 2019-08-06
8-K 2019-06-28
8-K 2019-06-06
8-K 2019-05-22
8-K 2019-05-07
8-K 2019-03-25
8-K 2019-02-28
8-K 2019-02-19
8-K 2019-01-07
8-K 2018-12-11
8-K 2018-11-29
8-K 2018-11-27
8-K 2018-11-15
8-K 2018-11-06
8-K 2018-10-26
8-K 2018-09-25
8-K 2018-09-18
8-K 2018-09-18
8-K 2018-09-18
8-K 2018-08-31
8-K 2018-08-14
8-K 2018-08-14
8-K 2018-08-08
8-K 2018-06-18
8-K 2018-06-07
8-K 2018-05-25
8-K 2018-05-08
8-K 2018-04-23
8-K 2018-02-13
8-K 2018-01-24
8-K 2018-01-24
8-K 2018-01-24

FANG 10K Annual Report

Part I
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10 - K Summary
EX-10.4 diamondback202010-kxex104.htm
EX-10.5 diamondback202010-kxex105.htm
EX-10.11 diamondback202010-kxex1011.htm
EX-21.1 diamondback202010-kxex211.htm
EX-23.1 diamondback202010-kxex231.htm
EX-23.2 diamondback202010-kxex232.htm
EX-23.3 diamondback202010-kxex233.htm
EX-31.1 diamondback202010-kxex311.htm
EX-31.2 diamondback202010-kxex312.htm
EX-32.1 diamondback202010-kxex321.htm
EX-32.2 diamondback202010-kxex322.htm
EX-99.1 diamondback202010-kxex991.htm
EX-99.2 diamondback202010-kxex992.htm

Diamondback Energy Earnings 2020-12-31

Balance SheetIncome StatementCash Flow
25201510502012201420172020
Assets, Equity
1.10.90.70.40.20.02016201720182020
Rev, G Profit, Net Income
0.70.2-0.3-0.9-1.4-1.92012201420172020
Ops, Inv, Fin

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Table of Contents
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, 2020
    
OR
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 ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per shareFANGThe 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:
Large Accelerated FilerAccelerated Filer
Non-Accelerated FilerSmaller Reporting Company
Emerging Growth Company
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
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 30, 2020 was approximately $6.6 billion.
As of February 19, 2021, 158,015,647 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2021 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, 2020
TABLE OF CONTENTS
Page
S-1






Table of Contents
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K, which we refer to as this Annual Report or this report:
3-D seismicGeophysical 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.
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOEOne barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBarrels of oil equivalent per day.
Brent
Brent sweet light crude oil.
British Thermal Unit or BTUThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe 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.
CondensateLiquid hydrocarbons associated with the production that is primarily natural gas.
Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Developed acreageAcreage assignable to productive wells.
Development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
DifferentialAn 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 wellA 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 EUREstimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
ExploitationA 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.
FieldAn 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 costsCapital 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.
FracturingThe 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 wellsThe total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drillingA 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 wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBblsOne thousand barrels of crude oil or other liquid hydrocarbons.
MBOEOne 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.
McfOne thousand cubic feet of natural gas.
Mcf/dOne thousand cubic feet of natural gas per day.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuOne million British Thermal Units.
MMcfMillion cubic feet of natural gas.
Net acres or net wellsThe sum of the fractional working interest owned in gross acres.
Net revenue interestAn owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
ii

Table of Contents
Net royalty acresGross acreage multiplied by the average royalty interest.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
PlayA 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 abandonmentRefers 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.
PUDProved undeveloped.
Productive wellA 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.
ProspectA 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 reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reservesThe 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 reservesProved 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.
RecompletionThe 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.
ReservesReserves 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).
ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Resource playA 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 interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
SpacingThe 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 formationA formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Undeveloped acreageLease 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.
Working interestAn 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.
WTIWest Texas Intermediate.

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GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this Annual Report.
ASUAccounting Standards Update.
CompanyDiamondback 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.
2025 IndentureThe 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.
2025 Senior Notes
The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
December 2019 Notes IndentureThe 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.
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.
May 2020 Notes
The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture.
NYMEXNew York Mercantile Exchange.
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.
Ryder Scott
Ryder Scott Company, L.P.
SEC
Securities and Exchange Commission.
SEC PricesUnweighted arithmetic average oil and natural gas prices as of the first day of the month for the most recent 12 months as of the balance sheet date.
Securities Act
The Securities Act of 1933, as amended.
Senior NotesThe 2025 Senior Notes, the December 2019 Notes and the May 2020 Notes.
ViperViper Energy Partners LP, a Delaware limited partnership.
Viper’s general partnerViper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLCViper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Wells Fargo
Wells Fargo Bank, National Association.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Annual Report are “forward-looking statements” as defined by the SEC. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, 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.

Forward-looking statements may include statements about:

the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Counties, or OPEC, members and other oil exporting nations;
the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, any government responses thereto and logistical challenges and the supply chain disruptions during the ongoing COVID-10 pandemic;
any impact of the ongoing COVID-19 pandemic on the health and safety of our employees;
logistical challenges and the supply chain disruptions;
changes in general economic, business or industry conditions;
conditions in the capital, financial and credit markets and our ability to obtain capital needed for development and exploration operations on favorable terms or at all;
conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;
U.S. and global economic conditions and political and economic developments, including the effects of the recent U.S. presidential and congressional elections on energy and environmental policies;
our ability to execute our business and financial strategies;
exploration and development drilling prospects, inventories, projects and programs;
levels of production;
the impact of reduced drilling activity on our exploration and development drilling prospects, inventories, projects and programs;
regional supply and demand factors, delays, curtailments delays or interruptions of production, and any governmental order, rule of regulation that may impose production limits;
our ability to replace our oil and natural gas reserves;
our ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our pending merger with QEP Resources, Inc., or QEP, and the Pending Guidon Acquisition (defined below);
competition in the oil and natural gas industry;
title defects in our oil and natural gas properties;
uncertainties with respect to identified drilling locations and estimates of reserves;
the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;
the impact of severe weather conditions, including the recent winter storms in the Permian Basin, on our production;
restrictions on the use of water;
the availability of transportation, pipeline and storage facilities;
our ability to comply with applicable government laws and regulations and to obtain permits and governmental approvals;
federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
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our environmental initiatives and targets;
future operating results;
future dividends to our stockholders;
impact of any impairment charges;
lease operating expenses, general and administrative costs and finding and development costs;
operating hazards;
civil unrest, terrorist attacks and cyber threats;
the effects of litigation relating to our pending merger with QEP and any future litigation;
our ability to keep up with technological advancements;
capital expenditure plans;
other plans, objectives, expectations and intentions; and
certain other factors discussed elsewhere in this report.

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. 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.
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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 Annual Report includes certain terms commonly used in the oil and natural gas industry, which are defined above in the “Glossary of Oil and Natural Gas Terms.”

ITEMS 1 and 2. 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 report operations in two operating segments: (i) the upstream segment and (ii) the midstream operations segment, which includes midstream services and real estate operations.

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. These formations are characterized by a high concentration of oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates.

At December 31, 2020, our total acreage position in the Permian Basin was approximately 449,642 gross (378,678 net) acres, which consisted primarily of approximately 215,956 gross (194,591 net) acres in the Midland Basin and approximately 192,697 gross (152,587 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 in the Permian Basin and Eagle Ford Shale. 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 72% of the limited partner interest in Rattler.

As of December 31, 2020, our estimated proved oil and natural gas reserves were 1,316,441 MBOE (which includes estimated reserves of 99,392 MBOE attributable to the mineral interests owned by Viper). Of these reserves, approximately 62% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 628 gross (559 net) horizontal well locations in which we have a working interest, and 38 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2020, our estimated proved reserves were approximately 58% oil, 22% natural gas liquids and 20% natural gas.

Pending Merger with QEP Resources, Inc.

On December 20, 2020, we, QEP Resources, Inc., or QEP, and Bohemia Merger Sub, Inc., our wholly owned subsidiary, or the Merger Sub, entered into an Agreement and Plan of Merger, which is referred to as the merger agreement, under which Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary, which we refer to as the pending merger. If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held immediately prior to the closing of the pending merger, 0.050 of a share of our common stock.

The completion of the pending merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including (a) the receipt of the required approvals from QEP’s stockholders, (b) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, or the HSR Act, (c) the absence of any governmental order or law that makes consummation of the pending merger illegal or otherwise prohibited, (d) the effectiveness of the registration statement on Form S-4 relating to the shares of our common stock to be issued in connection with the pending merger, which registration statement was declared effective by the SEC on February 10, 2021, and (e) the authorization for listing of such common stock on the Nasdaq Global Select Market. The obligation of each party to consummate the pending merger is also conditioned upon the other party’s representations and warranties being true and correct (subject to certain materiality exceptions), the other party having performed in all material respects its obligations
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under the merger agreement, and the receipt of an officer’s certificate from the other party to such effect. For additional information regarding the pending merger and our expectations relating to the combined company, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Pending Guidon Acquisition

On December 18, 2020, we and Diamondback E&P LLC, our wholly owned subsidiary, entered into a definitive, purchase and sale agreement with Guidon Operating LLC, or Guidon, and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the Pending Guidon Acquisition. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment. The Pending Guidon Acquisition is expected to close on February 26, 2021.

COVID-19

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply, and then continued to decline reaching negative levels. During 2020, the average NYMEX WTI futures contract price for crude oil and condensate was $39.34 per barrel and the average Henry Hub futures contract price for natural gas was $2.13 per million British thermal units (MMBtu), representing decreases of 31% and 16%, respectively, from the comparable average futures prices during 2019. These decreases were the result of multiple factors affecting supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021. We cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budget and production guidance, curtailed near term production and reduced rig count, all of which may be subject to further reductions or curtailment if the commodity markets and macroeconomic conditions worsen. Although we have restored curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows. For additional details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview.”

Given the dynamic nature of the events described above, we cannot reasonably estimate the period of time that the ongoing COVID-19 pandemic, the depressed commodity prices, the reduced demand for oil and the adverse macroeconomic conditions will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.

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.

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
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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 and focus on continuous improvement in operational, capital allocation 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 98% 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. Most recently, in December 2020, we entered into the merger agreement with QEP to acquire QEP in an all-stock transaction valued at approximately $2.2 billion, including QEP’s net debt of $1.6 billion as of September 30, 2020. The pending merger, upon closing, will add material Tier-1 Midland Basin inventory. In December 2020, we also entered into a definitive purchase and sale agreement with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets. 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, 2020, our borrowing base was set at $2.0 billion and we had $1.98 billion available for borrowing. As of December 31, 2020, Viper LLC had $84 million in outstanding borrowings, and $496 million available for borrowing, under its revolving credit facility. As of December 31, 2020, Rattler LLC had $79 million in outstanding borrowings, and $521 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, 2020 was approximately 60% oil, 20% natural gas liquids and 20% natural gas. As of December 31, 2020, our estimated net proved reserves were comprised of approximately 58% oil, 22% natural gas liquids and 20% 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 10,413 gross (6,863 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 8,200 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 3,610 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.

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Experienced, incentivized and proven management team. Our executive 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.

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 98% 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 395,000 gross acres across all of Rattler’s service lines and over the core of the Midland and Delaware Basins.

Our Properties

Location and Land

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. As of December 31, 2020, our total acreage position in the Permian Basin was approximately 449,642 gross (378,678 net) acres, which consisted primarily of approximately 215,956 gross (194,591 net) acres in the Midland Basin and approximately 192,697 gross (152,587 net) acres in the Delaware Basin. We are the operator of approximately 98% of this Permian Basin acreage. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 787,264 gross acres and 24,350 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 52% of these net royalty acres are operated by us.

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. We believe 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 producing wells in which we have a working interest in as of December 31, 2020:
BasinNumber of Horizontal Wells
Midland1,408 
Delaware917 
Other55 
Total(1)
2,380 
(1) Of these 2,380 total horizontal producing wells, we are the operator of 1,694 wells and have a non-operated working interest in 686 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, 2020:
Average Days to Total Depth
Midland Basin
7,500 foot lateral12 
10,000 foot lateral13 
13,000 foot lateral17 
Delaware Basin
7,500 foot lateral16 
10,000 foot lateral18 
13,000 foot lateral26 

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

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, 2020, Rattler owned and operated 927 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, 2020, Rattler also owned (i) a 10% equity interest in EPIC Crude Holdings LP, which owns and operates a long-haul crude oil pipeline from the Permian Basin and the Eagle Ford Shale to Corpus Christi, Texas that is capable of transporting approximately 600,000 Bbl/d, which began full operations in April 2020 and is referred to as the EPIC pipeline, (ii) a 10% equity interest in Gray Oak Pipeline, LLC, which owns and operates a long-haul crude oil pipeline that is capable of 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 began full operations in April 2020 and is referred 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 full commercial operations expected in the fourth quarter of 2021 will be capable of transporting approximately 1,500,000 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, which operates approximately 235 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 owns and operates 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. For additional information regarding our equity method investments as of December 31, 2020, see Note 10—Equity Method Investments to our consolidated financial statements included elsewhere in this Annual Report.

Rattler also owns and operates certain real estate assets in Midland, Texas including the Fasken Center which has over 421,000 net rentable square feet within its two office towers.

Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Strawn, Atoka and Barnett 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.


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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.

By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Permian Spraberry, Dean and Wolfcamp formations, which we collectively refer to as 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, 2020, we held working interests in 4,326 gross (3,401 net) producing wells and only royalty interests in 4,553 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 natural gas production from several stacked reservoirs of varying age ranges, most notably Permian aged sediments. In particular, the Permian aged Wolfcamp, Spraberry and 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 the Wolfcamp, Spraberry and 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 and Bone Spring Formations were 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, Spraberry and 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, Spraberry and 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.

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 3,610 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 resources to be exploited.

Production Status

During the year ended December 31, 2020, net production from our acreage was 109,921 MBOE, or an average of 300,331 BOE/d, of which approximately 60% was oil, 20% was natural gas liquids and 20% was natural gas.

 
Recent and Future Activity

During 2021, we expect to complete an estimated 215 to 235 gross (197 to 215 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2021 for drilling and infrastructure will be between $1.4 billion and $1.6 billion, consisting of $1.2 billion to $1.4 billion for horizontal drilling and completions including non-operated activity, $60 million to $80 million for midstream investments, excluding joint venture investments, and $70 million to $90 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, 2020, we drilled 208 gross (195 net) and completed 171 gross (159 net) operated horizontal wells. During the year ended December 31, 2020, our capital expenditures for drilling, completing and equipping wells were $1.6 billion. In addition, we spent $248 million for oil and natural gas midstream and infrastructure.
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We were operating eight drilling rigs at December 31, 2020 and currently intend to operate between eight and 12 rigs on average in 2021. 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.
Based on our evaluation of applicable geologic and engineering data, we currently have approximately 10,413 gross (6,863 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI. With our current development plan, we expect to continue our strong PUD conversion ratio in 2021 by converting an estimated 30% of our PUDs to a proved developed category and developing approximately 80% of the consolidated 2020 year-end PUD reserves by the end of 2023.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Reserves

Our historical reserve estimates as of December 31, 2020, 2019 and 2018 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 reserves as of December 31, 2020 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 natural 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 natural 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. Approximately 90% 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 10% 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.

The process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in “Item 1A. Risk Factors” of this report. As a result, 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
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information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.

Our Executive Vice President–Chief Engineer is primarily responsible for overseeing the preparation of all our reserve estimates. Our Executive Vice President–Chief Engineer 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 natural gas production, well test data, commodity prices and operating and development costs.

The preparation of our proved reserve estimates is 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–Chief Engineer or under his direct supervision;
review by our Executive Vice President–Chief Engineer 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–Chief Engineer 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.

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2020, 2019 and 2018 (including those attributable to Viper), based on the reserve reports prepared by Ryder Scott 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, 2020, none of our total proved reserves were classified as proved developed non-producing.
As of December 31,
202020192018
Estimated Proved Developed Reserves:
Oil (MBbls)443,464 457,083 403,051 
Natural gas (MMcf)1,085,035 824,760 705,084 
Natural gas liquids (MBbls)192,495 165,173 125,509 
Total (MBOE)816,798 759,716 646,074 
Estimated Proved Undeveloped Reserves:
Oil (MBbls)315,937 253,820 223,885 
Natural gas (MMcf)522,029 294,051 343,565 
Natural gas liquids (MBbls)96,701 65,030 64,782 
Total (MBOE)499,643 367,859 345,928 
Estimated Net Proved Reserves:
Oil (MBbls)759,401 710,903 626,936 
Natural gas (MMcf)1,607,064 1,118,811 1,048,649 
Natural gas liquids (MBbls)289,196 230,203 190,291 
Total (MBOE)(1)
1,316,441 1,127,575 992,001 
Percent proved developed62%67%65%
(1)Estimates of reserves as of December 31, 2020, 2019 and 2018 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, 2020, 2019 and 2018, respectively, in accordance with SEC guidelines. 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, all of which are located within the continental United States. 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. See “Item 1A. Risk Factors” for a discussion of risks and uncertainties associated with our estimates of proved reserves and related factors, and see Note 20—Supplemental Information on Oil and Natural Gas Operations for further discussion of our reserve estimates and pricing.

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Proved Undeveloped Reserves (PUDs)

As of December 31, 2020, our proved undeveloped reserves totaled 315,937 MBbls of oil, 522,029 MMcf of natural gas and 96,701 MBbls of natural gas liquids, for a total of 499,643 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table includes the changes in PUD reserves for 2020 (MBOE):
Beginning proved undeveloped reserves at December 31, 2019367,859 
Undeveloped reserves transferred to developed(89,133)
Revisions(15,742)
Purchases964 
Divestitures(14)
Extensions and discoveries235,709 
Ending proved undeveloped reserves at December 31, 2020499,643 

The increase in proved undeveloped reserves was primarily attributable to extensions of 220,023 MBOE from 277 gross (236 net) wells in which we have a working interest and 15,686 MBOE from 299 gross wells in which Viper owns royalty interests. Of the 277 gross working interest wells, 98 were in the Delaware Basin. Transfers of 89,133 MBOE from undeveloped to developed reserves were the result of drilling or participating in 102 gross (94 net) horizontal wells in which we have a working interest and 82 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 78 of the 82 gross Viper wells. Downward revisions of 15,742 MBOE were the result of (i) negative revisions of 4,226 MBOE due to lower product pricing, which were partially offset by positive revisions of 1,494 MBoe associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 2,732 MBOE, and (ii) PUD downgrades of 26,329 MBOE are primarily from changes in the corporate development plan. These negative revisions were offset with positive revisions of 13,319 MBOE associated with less gas flaring and a corresponding increase in shrunk gas and natural gas liquid recoveries.

Costs incurred relating to the development of PUDs were approximately $381 million during 2020. Estimated future development costs relating to the development of PUDs are projected to be approximately $676 million in 2021, $764 million in 2022, $859 million in 2023 and $531 million in 2024. Since our formation in 2011, our average drilling costs and drilling times have been reduced, and 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, 2020, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.


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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 10,413 gross (6,863 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data. 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)
1,015
Middle Spraberry(2)
1,074
Wolfcamp A(3)
909
Wolfcamp B(3)
1,006
Other2,111
Total Midland Basin6,115
Delaware Basin
2nd Bone Springs(4)
870
3rd Bone Springs(4)
1,222
Wolfcamp A(5)
854
Wolfcamp B(6)
755
Other597
Total Delaware Basin4,298
Total10,413
(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 is based on 880 foot to 1,320 foot spacing.
(5)Our current location count is based on 880 foot to 1,056 foot spacing.



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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:
Midland BasinDelaware Basin
Other(1)(2)
Total
(in thousands)
Production Data:
Year Ended December 31, 2020
Oil (MBbls)38,313 27,703 166 66,182 
Natural gas (MMcf)68,529 61,606 414 130,549 
Natural gas liquids (MBbls)12,597 9,295 89 21,981 
Total (MBoe)62,332 47,266 324 109,921 
Year Ended December 31, 2019
Oil (MBbls)41,156 25,951 1,411 68,518 
Natural gas (MMcf)48,109 48,447 1,057 97,613 
Natural gas liquids (MBbls)10,485 7,826 187 18,498 
Total (MBoe)59,659 41,852 1,774 103,285 
Year Ended December 31, 2018
Oil (MBbls)24,698 9,288 381 34,367 
Natural gas (MMcf)21,674 12,416 579 34,669 
Natural gas liquids (MBbls)5,493 1,866 106 7,465 
Total (MBoe)33,803 13,223 584 47,610 
(1)Production data for the years ended December 31, 2020 and 2019 includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.
(2)Production data for the year ended December 31, 2018 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,
202020192018
Average Prices:
Oil ($ per Bbl)$36.41 $51.87 $54.66 
Natural gas ($ per Mcf)$0.82 $0.68 $1.76 
Natural gas liquids ($ per Bbl)$10.87 $14.42 $25.47 
Combined ($ per BOE)$25.07 $37.63 $44.73 
Oil, hedged ($ per Bbl)(1)
$40.34 $51.96 $51.20 
Natural gas, hedged ($ per MMbtu)(1)
$0.67 $0.86 $1.72 
Natural gas liquids, hedged ($ per Bbl)(1)
$10.83 $15.20 $25.46 
Average price, hedged ($ per BOE)(1)
$27.26 $38.00 $42.20 
Average Costs per BOE:
Lease operating expenses$3.87 $4.74 $4.31 
Production and ad valorem taxes1.77 2.40 2.79 
Gathering and transportation expense1.27 0.86 0.55 
General and administrative - cash component0.46 0.54 0.79 
Total operating expense - cash$7.37 $8.54 $8.44 
General and administrative - non-cash component$0.34 $0.46 $0.57 
Depletion11.30 13.54 12.50 
Interest expense, net1.79 1.66 1.83 
Merger and integration expense— — 0.77 
Total expenses$13.43 $15.66 $15.67 
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(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and includes gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.

Wells Drilled and Completed in 2020

The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2020:
Year Ended December 31, 2020
DrilledCompleted
AreaGrossNetGrossNet
Midland Basin133 125 93 85 
Delaware Basin75 70 78 74 
Total208 195 171 159 

As of December 31, 2020, we operated the following wells:
Vertical WellsHorizontal WellsTotal
AreaGrossNetGrossNetGrossNet
Midland Basin1,745 1,641 1,102 1,008 2,847 2,649 
Delaware Basin25 22 592 557 617 579 
Total1,770 1,663 1,694 1,565 3,464 3,228 

Productive Wells

As of December 31, 2020, we owned an average unweighted 79% working interest in 4,326 gross (3,401 net) productive wells and an average 1.8% royalty interest in 4,553 additional wells. Through our subsidiary Viper, we own an average 3.8% net revenue interest in 7,167 gross 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, 2020:
Gross WellsNet Wells
OilNatural GasTotalOilNatural GasTotal
Midland Basin5,397 29 5,426 2,740 10 2,750 
Delaware Basin1,904 158 2,062 630 19 649 
Other1,316 75 1,391 — 
Total productive wells8,617 262 8,879 3,372 29 3,401 


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Drilling Results

The following tables set 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, 2020
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive87 81 26 25 113 106 
Dry— — — — — — 
Exploratory:
Productive46 44 49 45 95 89 
Dry— — — — — — 
Total:
Productive133 125 75 70 208 195 
Dry— — — — — — 

Year Ended December 31, 2019
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive75 68 31 28 106 96 
Dry— — — — — — 
Exploratory:
Productive96 86 128 114 224 200 
Dry— — — — — — 
Total:
Productive171 154 159 142 330 296 
Dry— — — — — — 

Year Ended December 31, 2018
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive67 58 21 20 88 78 
Dry— — — — — — 
Exploratory:
Productive50 43 38 35 88 78 
Dry— — — — — — 
Total:
Productive117 101 59 55 176 156 
Dry— — — — — — 

As of December 31, 2020, we had 20 gross (19 net) operated wells in the process of drilling and 151 gross (141 net) in the process of completion or waiting on completion.

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Acreage

The following table sets forth information as of December 31, 2020 relating to our leasehold acreage:
Developed Acreage(1)
Undeveloped Acreage
Total Acreage(2)
BasinGrossNetGrossNetGrossNet
Midland119,073 99,751 96,883 94,840 215,956 194,591 
Delaware103,712 77,263 88,985 75,324 192,697 152,587 
Exploration107 107 38,097 28,838 38,204 28,945 
Conventional Permian40 38 2,745 2,517 2,785 2,555 
Total222,932 177,159 226,710 201,519 449,642 378,678 
(1)Does 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)Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.

Undeveloped acreage expirations

As of December 31, 2020, the following gross and net undeveloped acres are set to expire over the next four years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.

Acres Expiring
DelawareMidlandExploratoryTotal
Gross NetGrossNetGrossNetGrossNet
202113,727 8,149 24,099 21,093 23,474 22,063 61,300 51,305 
20229,634 1,063 3,294 813 659 165 13,587 2,041 
2023966 410 1,951 1,597 — — 2,917 2,007 
2024370 59 — — — — 370 59 
Total24,697