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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒
ýANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
2023     
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
Delaware45-4502447
(State or Other Jurisdiction of
Incorporation or Organization)
(IRSI.R.S. Employer
Identification Number)
500 West Texas
Suite 1200
Midland, Texas
100
Midland,TX79701
(Address of Principal Executive Offices)principal executive offices)(Zip Code)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  ý☒   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  ý☒
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  ý☒    No ¨☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ý☒    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý☐
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”filer,” “smaller reporting company” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
Act:
Large Accelerated Filer☒ýAccelerated Filer¨☐
Non-Accelerated Filer☐¨Smaller Reporting Company¨☐
Emerging Growth Companyo☐

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.    o☐
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. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements    ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b)    ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨☐    No  ý☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 20172023 was approximately $7,801,460,276.$23.4 billion.
As of February 7, 2018, 98,167,28916, 2024, 178,446,583 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Diamondback Energy, Inc.’s Proxy Statement for the 20182024 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K
10-K.




DIAMONDBACK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 20172023
TABLE OF CONTENTS
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PART I
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PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
46
47
4948
7064
7165
71121
71121
74123
123
PART III
74123
74123
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74123
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PART IV
74124
80128
S-1129



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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 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.
BasinArgus WTI HoustonGrade of oil that serves as a benchmark price for oil at Houston, Texas.
Argus WTI MidlandGrade of oil that serves as a benchmark price for oil at Midland, Texas.
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelStockOne 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
BOBarrelsOne barrel of crude oil.
BO/dOne BO per day.
BOEBarrelsOne 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.
BrentBrentA major trading classification of light sweet light crude oil.oil that serves as a benchmark price for oil worldwide.
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.
Henry HubNatural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
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.
MBblsThousandOne thousand barrels of crude oil or other liquid hydrocarbons.
MBOEMBOOne thousand barrels of crude oil.
MBO/dOne thousand barrels of crude oil per day.
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.
McfMBOE/dThousandOne thousand BOE per day.
McfOne thousand cubic feet of natural gas.
Mcf/dThousand 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.
MMBtuMillionOne million British Thermal Units.
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MMcfMillion cubic feet of natural gas.

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MMcf/dMillion cubic feet of natural gas per day.
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.
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.undeveloped reserves.
Productive wellA well that is found to be mechanically 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, or operations.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.
Stratigraphic playAn oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.
Structural playAn oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.
Tight formationA formation with low permeability that produces natural gas with very low flow rates for long periods of time.

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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.
Waha HubNatural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.
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.Intermediate, a light sweet blend of oil produced from fields in western Texas and is a grade of oil that serves as a benchmark for oil on the NYMEX.
WTI CushingGrade of oil that serves as a benchmark price for oil at Cushing, Oklahoma.

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GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report.
Annual Report:
ASUAccounting Standards Update.
Company
2012 PlanThe Company’s 2012 Equity Incentive Plan.
BisonBison Drilling and Field Services, LLC.
CompanyDiamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
EPADodd-Frank ActDodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173).
EPAU.S. Environmental Protection Agency.
Equity PlanThe Company’s 2021 Amended and Restated Equity Incentive Plan.
Exchange ActThe Securities Exchange Act of 1934, as amended.
FERCFASBFinancial Accounting Standards Board.
FERCFederal Energy Regulatory Commission.
GAAPAccounting principles generally accepted in the United States.
General Partner
LIBORViper Energy PartnersThe London interbank offered rate.
NasdaqThe Nasdaq Global Select Market.
NYMEXNew York Mercantile Exchange.
RattlerRattler Midstream LP, a Delaware limited partnership and a wholly owned subsidiary of the Company since 2022.
Rattler’s GPRattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly owned subsidiary of the Company.
Rattler LLCRattler Midstream Operating LLC, a Delaware limited liability company and the General Partnera wholly owned subsidiary of the Partnership.Company since 2022.
2024 IndentureThe 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 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.
NYMEXNew York Mercantile Exchange.
OSHAFederal Occupational Safety and Health Act.
PartnershipViper Energy Partners LP, a Delaware limited partnership.
Partnership agreementThe first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
Ryder ScottRyder Scott Company, L.P.
SECS&P 500Standard and Poor’s 500 index.
SECUnited States 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 ActThe Securities Act of 1933, as amended.
2024
Guaranteed Senior NotesThe Company’s 4.750%outstanding senior unsecured notes issued by Diamondback Energy, Inc. under indentures where Diamondback E&P is the sole guarantor, consisting of the 3.250% Senior Notes due 2024 in the aggregate principal amount of $500 million.2026, 3.500% Senior Notes due 2029, 3.125% Senior Notes due 2031, 6.250% Senior Notes due 2033, 4.400% Senior Notes due 2051, 4.250% Senior Notes due 2052 and 6.250% Senior Notes due 2053.
2025 Senior Notes
SOFRThe Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million.secured overnight financing rate.
Senior NotesTSRThe 2024 Senior Notes andTotal stockholder return of the 2025 Senior Notes.Company’s common stock.
ViperViper Energy, Inc.
Viper LLCViper Energy Partners L.P.LLC, a Delaware limited liability company and a subsidiary of Viper.
Viper LTIPNotesThe outstanding senior notes issued by Viper Energy, Partners L.P. Long Term Incentive Plan.Inc. under indentures where Viper Energy, Inc. is the sole guarantor, consisting of the 5.375% Senior Notes due 2027 and the 7.375% Senior Notes due 2031.
Viper OfferingThe Partnerships’ initial public offering.
Wells FargoWells Fargo Bank, National Association.
XOPStandard and Poor’s Oil and Gas Exploration and Production industry index.



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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 statementsThis Annual Report contains “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 ofAct, which involve risks, uncertainties, and uncertainties, many of which are beyond our control.assumptions. All statements, other than statements of historical fact, including statements regarding our strategy,our: future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position, estimated revenuesposition; reserve estimates and losses, projected costs, prospects,our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) are forward-looking statements. When used in this report, the words “could,“aim,” “anticipate,” “believe,” “anticipate,“continue,” “intend,“could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “continue,“model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “potential,“project,” “project”“seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to the Company are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular,Although we believe that the expectations and assumptions reflected in our forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond our control. Accordingly, forward-looking statements are not guarantees of future performance and our actual outcomes could differ materially from what we have expressed in our forward-looking statements.

Factors that could cause our outcomes to differ materially include (but are not limited to) the following:

•changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;
•the impact of public health crises, including epidemic or pandemic diseases and any related company or government policies or actions;
•actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;
•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates interest rates, and inflation rates, instability in the financial sector and concerns over a potential economic downturn or recession;
•regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
•physical and transition risks relating to climate change;
•restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;
•significant declines in prices for oil, natural gas, or natural gas liquids, which could (among other things) require recognition of significant impairment charges;
•changes in U.S. energy, environmental, monetary and trade policies;
•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development operations and our environmental and social responsibility projects;
•challenges with employee retention and an increasingly competitive labor market due;
•changes in availability or cost of rigs, equipment, raw materials, supplies, oilfield services;
•changes in safety, health, environmental, tax, and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change);
•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;
•lack of, or disruption in, access to adequate and reliable transportation, processing, storage and other facilities for our oil, natural gas, and natural gas liquids;
•failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas developments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance;
v
•difficulty in obtaining necessary approvals and permits;
•severe weather conditions;
•acts of war or terrorist acts and the governmental or military response thereto;
•changes in the financial strength of counterparties to our credit agreement and hedging contracts;
•changes in our credit rating;
•risks related to the pending Endeavor Acquisition (as defined below); and
•the other risk and factors discussed in this Annual Reportreport.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, we operate in a very competitive and rapidly changing environment and new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on Form 10–K, including under Part I, Item 1A. “Risk Factors” in this report, could affect our actual results andbusiness or the extent to which any factor, or combination of factors, may cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or impliedthose anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made 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;
acquisitions
identified drilling locations;
ability to obtain permits and governmental approvals;
technology;
financial strategy;
realized oil and natural gas prices;
production;
lease operating expenses, general and administrative costs and finding and development costs;
future operating results; and
plans, objectives, expectations and intentions.
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. 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.applicable law.


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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 reportAnnual 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.”


ITEM 1.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 primarily 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 beganreport operations in December 2007 with our acquisition of 4,174 net acres inone reportable segment, the Permian Basin. At December 31, 2017, our total acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres. In addition, we, through our subsidiary Viper Energy Partners LP, or Viper, own mineral interests underlying approximately 247,602 gross acres, 43,843 net acres and 9,570 net royalty acres primarily in Midland County, Texas in the Permian Basin. Approximately 36% 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 the general partner, and we own approximately 64% of the limited partner interest in Viper.upstream segment.


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 isThese 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, 2023, our total acreage position in the Permian Basin was approximately 607,877 gross (493,769 net) acres, which consisted primarily of 428,324 gross (349,707 net) acres in the Midland Basin and 174,828 gross (143,742 net) acres in the Delaware Basin.

In addition, our publicly traded subsidiary Viper Energy, Inc., which we refer to as Viper, owns mineral interests primarily in the Permian Basin. We own approximately 56% of Viper’s outstanding shares of common stock.

As of December 31, 2017,2023, our estimated proved oil and natural gas reserves were 335,3522,177,761 MBOE (which includes estimated reserves of 38,246179,249 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,. As of December 31, 2023, approximately 62.2%69% are classified as proved developed producing. Proved undeveloped, or PUD, reserves included in this estimate are from 168802 gross (142(719 net) horizontal well locations in which we have a working interest, and nine horizontal wells in which we own only a mineral interest through our subsidiary, Viper.interest. As of December 31, 2017,2023, our estimated proved reserves were approximately 70%53% oil, 14%23% natural gas liquids and 16%24% natural gas.gas liquids.


BasedSignificant Recent Acquisitions and Divestitures

GRP Acquisition

On November 1, 2023, Viper acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP and affiliates of Warwick Capital Partners and GRP Energy Capital (collectively, “GRP”), pursuant to a definitive purchase and sale agreement in exchange for approximately 9.02 million Viper common units and $760 million in cash consideration, including transaction costs and subject to customary post-closing adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired included 4,600 net royalty acres in the Permian Basin, plus an additional 2,700 net royalty acres in other major basins.

Deep Blue Formation and Divestiture of Deep Blue Water Assets

On September 1, 2023, we closed on a joint venture agreement with Five Point Energy LLC (“Five Point”) to form Deep Blue Midland Basin LLC (“Deep Blue”). At closing, we contributed certain treated water, fresh water and saltwater disposal assets (the “Deep Blue Water Assets”) with a net carrying value of $692 million in exchange for $516 million in cash consideration and a 30% equity ownership and voting interest in Deep Blue and certain contingent consideration.

Lario Acquisition

On January 31, 2023, we closed on the acquisition of all leasehold interests and related assets of Lario Permian, LLC, a wholly owned subsidiary of Lario Oil and Gas Company, and certain associated sellers (collectively “Lario”), which included approximately 25,000 gross (16,000 net) acres in the Midland Basin and certain related oil and gas assets (the “Lario Acquisition”) in exchange for 4.33 million shares of our evaluationcommon stock and $814 million in cash consideration, including certain customary post-closing adjustments.

1
Table of applicable geologicContents
See Note 4—Acquisitions and engineering data,Divestitures in Item 8. Financial Statements and Supplementary Data of this report for additional discussion of our acquisitions and divestitures during 2023.

Pending Endeavor Acquisition

On February 11, 2024, we currently haveentered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Company, Eclipse Merger Sub I, LLC, Eclipse Merger Sub II, LLC, Endeavor Manager, LLC (solely for purposes of certain sections set forth therein), and Endeavor Parent, LLC (“Endeavor”) to acquire Endeavor (the “Endeavor Acquisition”) for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations117.27 million shares of our common stock. The Endeavor Acquisition is expected to close in multiple horizons onthe fourth quarter of 2024, subject to the satisfaction or waiver of customary closing conditions, including the approval of the issuance of our acreagecommon stock in the Endeavor Acquisition by our stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, Endeavor’s equityholders who receive shares of our common stock in the Endeavor Acquisition (the “Endeavor Stockholders”) are expected to hold, at an assumed priceclosing, approximately 39.5% 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.outstanding common stock.


The challenging commodity price environmentMerger Agreement provides that at the closing of the Endeavor Acquisition, we experienced in 2016 continued in 2017. Commodity prices improved during 2017, but continuedwill enter into an agreement with the Endeavor Stockholders (the “Stockholders Agreement”), which will provide the Endeavor Stockholders with certain director nomination rights, consent rights over certain actions by us and certain shelf, demand and piggyback registration rights. The Endeavor Stockholders will also be subject to certain standstill, voting and transfer restrictions under the Stockholders Agreement.

The foregoing descriptions of the Merger Agreement and the Stockholders Agreement do not purport to be volatile. Nevertheless, we believe we remain well-positionedcomplete and are qualified in their entirety by reference to the actual terms of the Merger Agreement and form of the Stockholders Agreement, copies of which are included hereto as Exhibits 2.3 and 99.3, respectively, and incorporated herein by reference.

See Note 16—Subsequent Events in Item 8. Financial Statements and Supplementary Data and Item 1A. Risk Factors of this environment. During 2017, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operationsreport for additional discussion of the Endeavor Acquisition and a conservative balance sheet as we continued to reduce drilling days, well costs and operating expenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2018, emphasizing full cycle economics and financial discipline. We are operating ten rigs now and currently intend to operate between ten and twelve rigs in 2018, depending on market conditions. 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. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigs in 2018 should commodity prices deteriorate. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”related risks.





Our Business Strategy


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


Grow production and reserves by developing•Exercise Capital Discipline. During 2023, we continued building on 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 andexecution track record, generating free cash flow while generating favorable returns on invested capital.

Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervalskeeping capital costs under control. Our efficiency gains, particularly in the Midland Basin through horizontal drilling and believe that there are opportunitiescompletion programs, enabled us to target additional intervalsmitigate certain inflationary pressures on variable well costs, which led to a total capital expenditure amount of $2.7 billion, consistent with our guidance presented in November 2023. We expect to continue to exercise capital discipline and plan to spend between $2.30 billion and $2.55 billion in 2024, with the goal of maintaining flat production throughout the stratigraphic column. Our initial horizontal focus had been onyear with less capital and activity than 2023. This capital range accounts for the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, Middle Spraberry and Wolfcamp A intervals. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, 2017, we had drilled 412 horizontal wells as operator and had participated in 61 additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. We also acquired interest in 76 horizontal wells on properties we purchased. Of these 549 total horizontal wells, 466 had been completed and were on production. Of the 466 horizontal wells on production, 152 are in the Wolfcamp B interval, 122 are in the Wolfcamp A interval, 163 are in the Lower Spraberry interval, nine are in the Middle Spraberry interval, three are in the Cline interval, three are in the Clearfork interval, seven are in the Bone Spring interval and seven are in various other intervals. These wells have lateral lengths ranging from approximately 2,100 feet to 13,000 feet. In 2018,inflationary pressures we expect to see in 2024.

•Focus on low cost development strategy and 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 our average lateral length will be about 9,300 feet, althoughtakes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the actual length will vary depending on the layoutoperator of approximately 98% of our acreage, which allows us to efficiently manage our operating costs, pace of development activities and other factors. As technology continuesthe gathering and marketing of our production. Our average 81% working interest in our acreage allows us to improve,realize the majority of the benefits of these activities and cost efficiencies.

•Continue to deliver on our enhanced capital return program. We expect to be in a position to continue to deliver on our enhanced capital return program, through which we expect thatintend to distribute 50% of our average lateral length will increase, resulting in higher per well recoveriesquarterly free cash flow to our stockholders. Our capital return program is currently focused on our sustainable and lower development costs per BOE. During the year ended December 31, 2017, we were able to drill our horizontal wells in the Midland Basin with approximately 7,500 foot lateral lengths to total depth, or TD, in an averagegrowing base dividend and a combination of 12.2 daysstock repurchases and we drilled approximately 10,000 foot lateral wells in 14.5 days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.
variable dividends.


•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 refiningoptimizing 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
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recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other top operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
practices compared to our peers.


Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 84% 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. OurWe believe 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. During the year ended December 31, 2017, we acquired approximately 99,830 gross (84,468 net) leasehold acres primarily in Pecos and Reeves counties in the Southern Delaware Basin.




•Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2017 borrowing base redetermination, the agent lender under our revolving credit agreement recommended a borrowing base of $1.8 billion. We elected a commitment amount of $1.0 billion, of which $603.0 million was available for borrowing as of December 31, 2017. As of December 31, 2017,2023, Diamondback had $556 million of standalone cash and cash equivalents and our borrowing base was set at $1.6 billion, which was fully available for future borrowings. As of December 31, 2023, Viper had $93.5$26 million of cash and cash equivalents, $263 million in outstanding borrowings and $306.5$587 million available for borrowing,future borrowings under its revolving credit facility.


•Deliver on our commitment to environmental, social and governance (“ESG”) performance. We are committed to the safe and responsible development of our resources in the Permian Basin. Our approach to ESG is evidenced through our commitment to people, safety, environmental responsibility, community and sound governance practices. In September 2022, we announced our medium-term goal to reduce Scope 1 and Scope 2 greenhouse gas (“GHG”) intensity by at least 50%, from 2020 levels by 2030.

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 Substantially 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, 2017 was approximately 74% oil, 14% natural gas liquids and 12% natural gas. As of December 31, 2017, our estimated net proved reserves were comprised of approximately 70% oil, 14% natural gas liquids and 16% 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 economic price of approximately $60.00$50.00 per Bbl WTI, we currently have approximately 3,8007,905 gross (2,750(5,826 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 8,4009,407 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. Of these 3,800 locations, 2,100 are in the Midland Basin and 1,700 are in the Delaware Basin. In the Midland Basin, 860 are in the Lower Spraberry or Wolfcamp B horizons where we have drilled a large number of wells, 825 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wells and 415 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizon is based on 660 foot spacing in f Midland, southwest Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in all other counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin, northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and 1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count is based on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin, 1,240 locations are in the Wolfcamp A or Wolfcamp B horizons, and 460 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. The horizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the Bone Spring horizons. The ultimate inter-well spacing at these locations may vary from these distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2017, range from 528 MBOE per well, consisting of 413 MBbls of oil and 687 MMcf of natural gas, to 1,665 MBOE per well, consisting of 1,307 MBbls of oil and 2,150 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 12,500 feet, in intervals including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of 910 MBOE for our Lower Spraberry wells in Midland County and 1,071 MBOE for our Wolfcamp A wells in Pecos County, which constitute 36% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we have approximately 1,8375,596 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.


•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, ourOur 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.




•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 84%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, weWe retain the ability to increase or
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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.


Our Properties


Location and Land


Our total acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres at December 31, 2017. We are the operator of approximately 84% of this Permian Basin acreage. In addition, we, through our subsidiary Viper, own mineral interests underlying approximately 247,602 gross acres, 43,843 net acres and 9,570 net royalty acres primarily in the Permian Basin. Approximately 36% of these net royalty acres are operated by us. Since our initial acquisition in the Permian Basin through December 31, 2017, we drilled or participated in the drilling of 753 gross (608 net) wells on our leasehold acreage in this area, primarily targeting the Wolfberry play. 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, 2023, our total acreage position in the Permian Basin was approximately 607,877 gross (493,769 net) acres, which consisted primarily of 428,324 gross (349,707 net) acres in the Midland Basin and 174,828 gross (143,742 net) acres in the Delaware Basin. In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 1,197,638 gross acres (34,217 net) royalty acres in the Permian Basin. Approximately 49% of these net royalty acres are operated by us.


We have been developing multiple pay intervals primarily 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 as of December 31, 2023:
BasinNumber of Horizontal Wells
Midland2,455 
Delaware860 
Other41 
Total(1)
3,356 
(1) Of these 3,356 total horizontal producing wells, we are the operator of 2,950 wells and have a non-operated working interest in 406 additional wells.

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, 2023:
Average Days to Total Depth
Midland Basin
7,500 foot lateral7 
10,000 foot lateral10 
13,000 foot lateral12 
15,000 foot lateral12 
Delaware Basin
7,500 foot lateral17 
10,000 foot lateral17 
13,000 foot lateral20 
15,000 foot lateral18 

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

Equity Method Investments

As of December 31, 2023, we owned interests in the following significant equity method investments:

•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.
•a 4% equity interest in Wink to Webster Pipeline LLC, which owns and operates a crude oil pipeline that is 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.
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•a 25% equity interest in Remuda Midstream Holdings LLC, which we refer to as the WTG joint venture, which owns and operates an interconnected gas gathering system and seven major gas processing plants servicing the Midland Basin with 1,300 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.
•a 10% equity interest in BANGL LLC, which we refer to as the BANGL joint venture. The BANGL pipeline, which began full commercial service in the fourth quarter of 2021, provides NGL takeaway capacity from the MPLX and WTG gas processing plants in the Permian Basin to the NGL fractionation hub in Sweeny, Texas and has expansion capacity of up to 300,000 Bbl/d.
•a 30% equity interest in Deep Blue, which owns and operates an integrated midstream water infrastructure network with over 800 miles of gathering and redelivery pipelines for gathering, transport, disposal and reuse throughout the Midland Basin. Deep Blue has approximately 2,000,000 Bbl/d of produced water capacity and approximately 66,000,000 Bbl/d of water storage capacity.

For additional information regarding our equity method investments as of December 31, 2023, see Note 7—Equity Method Investments and Related Party Transactions in Item 8. Financial Statements and Supplementary Data of this report.

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, Atoka, Barnett and AtokaWoodford 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 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, 2017,2023, we held working interests in 1,1666,156 gross (937(5,342 net) producing wells and only royalty interests in 6414,696 additional wells.


Geology


The greater Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence.influence of the Marathon Uplift and Ancestral Rockies. It is one of the largestmost productive sedimentary basins in the U.S., with established oil and natural gas production from several stacked reservoirs fromof varying age ranges, most notably Permian through Ordovician in age. The term “Wolfberry” was coined initially to indicate commingled production from


aged sediments. In particular, the Permian aged Wolfcamp, Spraberry Dean and Wolfcamp formations. Time equivalent in the Delaware Basin, the “Wolfbone” play describes vertically commingled production from the Permian Bone Spring Formations have been heavily targeted for several decades. First, through vertical commingling of these zones and, more recently, through horizontal exploitation of each individual horizon. Prior to deposition of the Wolfcamp, formations.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 lead to deposits of organically rich mudstone such as the Devonian Woodford and Mississippian Barnett. These formations are important sources and, more recently, reservoirs within the present-day Greater Permian Basin.


The Spraberry/Spraberry and Bone Spring wasFormations were deposited as siliciclastic and carbonate turbidites and debris flows along with pelagic mudstones in a deep water submarine fandeep-water, basinal environment, while the Wolfcamp reservoirs consist of debris-flow, grain-flow and grain-flowfine-grained pelagic sediments, which were also deposited in a submarine fanbasinal setting. The best carbonate reservoirs within the Wolfcamp, Spraberry and Bone Spring are generally found in close proximity to the Central Basin Platform, while the shalemudstone reservoirs within the Wolfcamp thicken basinwardbasin-ward, away from the Central Basin Platform. Both the Spraberry/Bone Spring and Wolfcamp contain organic-rich mudstones and shalesThe 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 shalesmudstones themselves and in the moreinterbedded conventional clastic and carbonate reservoirs betweenreservoirs. Due to this complexity, the shales.  The WolfberryWolfcamp, Spraberry and WolfboneBone Spring intervals are a hybrid reservoir system that contains characteristics of both unconventional “basin-centered oil” resource plays, in the sense that there is no regional downdip oil/water contact.and conventional reservoirs.
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We have successfully developed several shalehybrid reservoir intervals within the Clearfork, Spraberry/Bone Spring, Wolfcamp, Barnett and WolfcampWoodford formations since we began horizontal drilling in 2012. The shalesmudstones 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 1,8375,596 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 resourceresources to be exploited.

Production Status

During the year ended December 31, 2017, net production from our Permian Basin acreage was 28,917 MBOE, or an average of 79,224 BOE/d, of which approximately 74% was oil, 14% was natural gas liquids and 12% 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.


 
Recent and Future Activity


During 2018,2024, we expect to drill an estimated 265 to 285 gross (244 to 263 net) operated horizontal wells and complete an estimated 170300 to 190320 gross (146(273 to 163291 net) operated horizontal wells on our acreage. We currently estimate that our capital expenditures in 2018 for drilling and infrastructure2024 will be between $1.3$2.30 billion and $1.5$2.55 billion, consisting of $1.175$2.10 billion to $1.325$2.33 billion for horizontal drilling and completions including non-operated activity and $125.0capital workovers, $200 million to $175.0$220 million for infrastructure and other expenditures, butmidstream investments, excluding joint venture investments and the cost of any leasehold and mineral rightsinterest acquisitions. During the year ended December 31, 2017,2023, we drilled 150350 gross (130(315 net) and completed 123310 gross (105(289 net) operated horizontal wells including five drilled but uncompleted wells we acquired. We participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin. During the year ended December 31, 2017, ourand incurred capital expenditures for drilling, completing and equipping wells were $719.3 million.and infrastructure additions to oil and natural gas properties of $2.6 billion. In addition, we spent $124.0$119 million for oil and natural gas infrastructure, $17.4 million for non-operated properties and $2.4 billion for leasehold and mineral rights acquisitions.midstream assets.


We arewere operating ten15 drilling rigs nowand four completion crews at December 31, 2023 and currently intend to operate between ten12 and twelve15 rigs and three and four completion crews on average in 2018, depending on market conditions.2024. 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. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigs in 2018 should commodity prices deteriorate.

Oil and Natural Gas Data


Proved Reserves


Evaluation and Review of Reserves


The estimated reserves as of December 31, 2023 and 2022 are based on reserve estimates prepared by our internal reservoir engineers and audited by Ryder Scott, an independent petroleum engineering firm. Our historical reserve estimates as of December 31, 2017, 2016 and 20152021 were prepared by Ryder Scott with respect to our assetsScott. The internal and those of Viper. Ryder Scott is an independent petroleum engineering firm. Theexternal technical persons responsible for preparing or auditing 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. The purpose of Ryder Scott’s audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates and covered 100% of our total proved reserves for 2023 and 2022.




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, 20172023 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)(i) performance-based methods, (2)(ii) volumetric-based methods and (3)(iii) 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 forIn general, our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 83% 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 17%In certain cases
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where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was considered to be inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there werewas 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 Scottwe 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.


WeThe process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment, as discussed in Item 1A. Risk Factors and Item 7. Management Discussion and Analysis—Critical Accounting Estimates of this report. As a result, we maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineersthat have an internal control process to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin.reserves. Our internal technical team membersstaff met with our independent reserve engineersauditor periodically during their audit of the period covered by the reserve reports to discuss the assumptions and methods used in theour proved reserve estimation process. WeAs part of the audit process, we provide historical 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

The Executive Vice President–Reservoir EngineeringPresident and Chief Engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. Ourestimates and overseeing communications with our independent reserve auditor. The Executive Vice President–Reservoir EngineeringPresident and Chief Engineer is a petroleum engineer with over 3020 years of reservoir and operations experience and our geoscience staff has an average of approximately 2415 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. Ryder Scott performed an independent analysis during its audit of our estimated reserves for 2023 and any differences were reviewed with our Executive Vice President and Chief Engineer. For 2023, our reserve auditor’s estimates of our proved reserves did not materially differ from our estimates by more than the established audit tolerance guidelines of ten percent.


The internal control procedures utilized in 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, and 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 Engineeringthe primary reserve engineers or under histheir direct supervision;

•review by our Executive Vice President–Reservoir Engineeringthe primary reserve engineers 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;

•review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
•direct reporting responsibilities by our Executive Vice President–Reservoir EngineeringPresident and Chief Engineer to our Executive Vice President—Operations;
•prior to finalizing the reserve report, a review of our preliminary proved reserve estimates by our Chief Executive Officer;Officer, President and Chief Financial Officer, Executive Vice President and Chief Operating Officer, Executive Vice President and Chief Engineer and our primary reserves engineers takes place on an annual basis;

•review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott on an annual basis;
•verification of property ownership by our land department; and

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



For estimates and further discussion of our proved developed and proved undeveloped reserves, see Note 18—Supplemental Information on Oil and Natural Gas Operations in Item 8. Financial Statements and Supplementary Data of this report.


Potential Drilling Locations

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 $50.00 per Bbl WTI, we currently
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have approximately 7,905 gross (5,826 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.

The following table presents our estimated net proved oil and natural gas reserves asthe number of December 31, 2017, 2016 and 2015 (including those attributable to Viper),gross identified economic potential horizontal drilling locations by basin:
Number of Identified Economic Potential Horizontal Drilling Locations
Midland Basin
Lower Spraberry(1)
899
Middle Spraberry(1)
944
Wolfcamp A(2)
565
Wolfcamp B(2)
694
Other2,150
Total Midland Basin5,252
Delaware Basin
2nd Bone Springs(3)
582
3rd Bone Springs(3)
836
Wolfcamp A(3)
294
Wolfcamp B(3)
530
Other411
Total Delaware Basin2,653
Total7,905
(1)Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin and northeast Andrews counties, depending on the reserve reports prepared by Ryder Scott. Each reserve report has been preparedprospect area and 880 foot spacing 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.all other counties.
 December 31,
 2017 2016 2015
Estimated proved developed reserves:     
Oil (MBbls)141,246
 79,457
 60,569
Natural gas (MMcf)190,740
 105,399
 96,871
Natural gas liquids (MBbls)35,412
 22,080
 15,418
Total (MBOE)208,447
 119,104
 92,132
Estimated proved undeveloped reserves:     
Oil (MBbls)91,935
 59,717
 45,409
Natural gas (MMcf)94,629
 69,497
 52,632
Natural gas liquids (MBbls)19,198
 15,054
 10,586
Total (MBOE)126,905
 86,354
 64,767
Estimated Net Proved Reserves:     
Oil (MBbls)233,181
 139,174
 105,979
Natural gas (MMcf)285,369
 174,896
 149,503
Natural gas liquids (MBbls)54,610
 37,134
 26,004
Total (MBOE)(1)
335,352
 205,458
 156,899
Percent proved developed62.2% 58.0% 58.7%
(1)Estimates of reserves as of December 31, 2017, 2016 and 2015 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, 2017, 2016 and 2015, 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(2)Our current location count 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 variables660 foot to 880 foot spacing in Midland and assumptions,Howard counties, depending on the prospect area and 880 foot spacing in 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.counties.

(3)Our current location count is based on 880 foot to 1,320 foot spacing.
Proved Undeveloped Reserves (PUDs)

As of December 31, 2017, our proved undeveloped reserves totaled 91,935 MBbls of oil, 94,629 MMcf of natural gas and 19,198 MBbls of natural gas liquids, for a total of 126,905 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 2017:
(MBOE)
Beginning proved undeveloped reserves at December 31, 201686,354
Undeveloped reserves transferred to developed(31,666)
Revisions(4,710)
Net purchases6,246
Extensions and discoveries70,680
Ending proved undeveloped reserves at December 31, 2017126,904

The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which we have a working interest and 3,004 MBOE from 40 gross wells in which Viper owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which we have a working interest and 27 gross wells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 23 of the 27 gross Viper wells. Net purchases of 6,246 MBOE were primarily from our purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.

Costs incurred relating to the development of PUDs were approximately $145.4 million during 2017. Estimated future development costs relating to the development of PUDs are projected to be approximately $595.4 million in 2018, $205.6 million in 2019, $171.2 million in 2020 and $58.3 million in 2021. 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, 2017, 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, 2017, 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 table setstables set forth information regarding our net production of oil, natural gas and natural gas liquids allby basin for the fields containing 15% or more along with other production from fields containing less than 15% of our total proved reserves:
Midland BasinDelaware Basin
Other(1)(2)
Total
Production Data:
Year Ended December 31, 2023
Oil (MBbls)75,859 20,246 71 96,176 
Natural gas (MMcf)140,721 57,129 267 198,117 
Natural gas liquids (MBbls)25,899 8,296 22 34,217 
Total (MBOE)125,212 38,064 138 163,413 
Year Ended December 31, 2022
Oil (MBbls)58,803 22,681 132 81,616 
Natural gas (MMcf)116,579 59,338 459 176,376 
Natural gas liquids (MBbls)20,800 9,016 64 29,880 
Total (MBOE)99,033 41,587 273 140,892 
Year Ended December 31, 2021
Oil (MBbls)52,112 25,672 3,738 81,522 
Natural gas (MMcf)96,083 66,034 7,289 169,406 
Natural gas liquids (MBbls)17,010 8,749 1,487 27,246 
Total (MBOE)85,136 45,427 6,440 137,002 
(1)Production data includes Rockies and High Plains for the years ended December 31, 2023, 2022 and 2021, and Eagle Ford Shale through October 1, 2022, the effective date on which is fromit was divested.
(2)Production data includes Eagle Ford Shale, Appalachia, Barnett, Denver-Julesburg, Mid-Con, and Williston beginning November 1, 2023, the Permian Basin in West Texas, andeffective date on which the properties were acquired.
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The following table sets forth certain price and cost information for each of the periods indicated:
Year Ended December 31,
202320222021
Average Prices:
Oil ($ per Bbl)$75.68 $93.85 $66.19 
Natural gas ($ per Mcf)$1.32 $4.86 $3.36 
Natural gas liquids ($ per Bbl)$20.08 $35.07 $28.70 
Combined ($ per BOE)$50.35 $67.90 $49.25 
Oil, hedged ($ per Bbl)(1)
$74.72 $86.76 $52.56 
Natural gas, hedged ($ per Mcf)(1)
$1.48 $4.12 $2.39 
Natural gas liquids, hedged ($ per Bbl)(1)
$20.08 $35.07 $28.33 
Average price, hedged ($ per BOE)(1)
$49.98 $62.85 $39.87 
Average Costs per BOE:
Lease operating expenses$5.34 $4.63 $4.12 
Production and ad valorem taxes3.21 4.34 3.10 
Gathering, processing and transportation expense1.76 1.83 1.55 
General and administrative - cash component0.59 0.63 0.69 
Total operating expense - cash$10.90 $11.43 $9.46 
General and administrative - non-cash component$0.33 $0.39 $0.37 
Depreciation, depletion, amortization and accretion per BOE10.68 9.54 9.31 
Interest expense, net1.07 1.13 1.45 
Merger and integration expense0.07 0.10 0.57 
Total operating expense - non-cash$12.15 $11.16 $11.70 
Production Costs(2)
$7.10 $6.46 $5.67 
 Year Ended December 31,
 2017 2016 2015
Production Data:     
Oil (MBbls)21,418
 11,562
 9,081
Natural gas (MMcf)20,660
 10,728
 7,931
Natural gas liquids (MBbls)4,056
 2,399
 1,678
Combined volumes (MBOE)28,917
 15,749
 12,081
Daily combined volumes (BOE/d)79,224
 43,031
 33,098
      
Average Prices:     
Oil (per Bbl)$48.75
 $40.70
 $44.68
Natural gas (per Mcf)2.53
 2.10
 2.47
Natural gas liquids (per Bbl)22.20
 14.20
 12.77
Combined (per BOE)41.02
 33.47
 36.98
Oil, hedged ($ per Bbl)(1)
48.94
 40.80
 60.63
Natural gas, hedged ($ per MMbtu)(1)
2.65
 2.06
 2.47
Average price, hedged ($ per BOE)(1)
41.26
 33.54
 48.97
      
Average Costs per BOE:     
Lease operating expense$4.38
 $5.23
 $6.84
Production and ad valorem taxes2.54
 2.19
 2.73
Gathering and transportation expense0.44
 0.74
 0.50
General and administrative - cash component0.80
 1.03
 1.11
Total operating expense - cash8.16
 9.19
 11.18
      
General and administrative - non-cash component0.88
 1.68
 1.54
Depreciation, depletion and amortization11.30
 11.30
 18.02
Interest expense1.40
 2.58
 3.44
Total expenses$13.58
 $15.56
 $23.00
(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.

(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Productive Wells(2)Average production costs exclude production and ad valorem taxes.


Wells Drilled and Completed in 2023

The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2023:
Year Ended December 31, 2023
DrilledCompleted
Area:GrossNetGrossNet
Midland Basin315 285 263 246 
Delaware Basin35 30 47 43 
Total350 315 310 289 

As of December 31, 2017,2023, we operated the following wells:
Vertical WellsHorizontal WellsTotal
Area:GrossNetGrossNetGrossNet
Midland Basin2,641 2,499 2,269 2,088 4,910 4,587 
Delaware Basin37 35 681 633 718 668 
Total2,678 2,534 2,950 2,721 5,628 5,255 

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Productive Wells

As of December 31, 2023, we owned an interest in a total of 20,852 gross productive wells with an average unweighted 80%87% working interest in 1,1666,156 gross (937(5,342 net) productive wells and an average 2.7%2.4% royalty interest in 6414,696 additional wells. Through our subsidiary Viper, we own an average unweighted 9.2% royalty or mineral2.5% net revenue interest in 1,28714,893 of the total 20,852 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.



Acreage


The following table sets forth information regarding productive wells by basin as of December 31, 2017 relating to our leasehold acreage:2023:
Gross WellsNet Wells
OilNatural GasTotalOilNatural GasTotal
Midland Basin14,137 36 14,173 4,633 9 4,642 
Delaware Basin3,406 494 3,900 677 22 699 
Denver-Julesburg Basin1,435 118 1,553 — — — 
Williston Basin721 2 723 — — — 
Other(1)
291 212 503 1 — 1 
Total productive wells19,990 862 20,852 5,311 31 5,342 
 
Developed Acreage(1)
 
Undeveloped Acreage(2)
 
Total Acreage(3)
Basin
Gross(4)
 
Net(5)
 
Gross(4)
 
Net(5)
 
Gross(4)
 
Net(5)
Delaware58,444
 49,919
 69,982
 54,800
 128,426
 104,719
Midland84,325
 69,641
 33,261
 32,300
 117,586
 101,941
Total142,769
 119,560
 103,243
 87,100
 246,012
 206,660
(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)Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
(3)Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.
(4)A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(5)A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

(1)Other productive wells include the Eagle Ford Basin, Appalachia Basin, Mid-Con, Rockies Basin and Barnett Basin.
Undeveloped acreage expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2017, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
 2018 2019 2020 2021 2022
BasinGross Net Gross Net Gross Net Gross Net Gross Net
Delaware28,572
 22,198
 31,091
 19,415
 13,097
 1,286
 3,639
 719
 —
 —
Midland897
 715
 908
 255
 19,678
 18,933
 —
 —
 —
 —
Total29,469
 22,913
 31,999
 19,670
 32,775
 20,219
 3,639
 719
 —
 —




Drilling Results


The following table setstables set forth information with respect to the number of wells completeddrilled during the periods indicated.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, 2023
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive192 179 29 25 221 204 
Dry— — — — — — 
Exploratory:
Productive123 106 6 5 129 111 
Dry— — — — — — 
Total:
Productive315 285 35 30 350 315 
Dry— — — — — — 

Year Ended December 31, 2022
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive59 54 16 15 75 69 
Dry— — — — — — 
Exploratory:
Productive138 129 27 25 165 154 
Dry— — — — — — 
Total:
Productive197 183 43 40 240 223 
Dry— — — — — — 
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 Year Ended December 31,
 2017 2016 2015
 Gross Net Gross Net Gross Net
Development:           
Productive27
 23
 6
 3
 8
 6
Dry—
 —
 —
 —
 —
 —
Exploratory:           
Productive112
 84
 82
 62
 71
 57
Dry—
 —
 —
 —
 —
 —
Total:           
Productive139
 107
 88
 65
 79
 63
Dry—
 —
 —
 —
 —
 —



Year Ended December 31, 2021
Midland BasinDelaware BasinTotal
GrossNetGrossNetGrossNet
Development:
Productive33 30 7 7 40 37 
Dry— — — — — — 
Exploratory:
Productive142 135 34 31 176 166 
Dry— — — — — — 
Total:
Productive175 165 41 38 216 203 
Dry— — — — — — 

As of December 31, 2017,2023, we had 8317 gross (66(16 net) operated wells in the process of drilling and 205 gross (181 net) wells in the process of drilling, completingcompletion or dewatering or shut in awaiting infrastructurewaiting on completion.

Acreage

The following table sets forth information as of December 31, 2023 relating to our leasehold acreage:
Developed Acreage(1)
Undeveloped Acreage
Total Acreage(2)
BasinGrossNetGrossNetGrossNet
Midland218,357 191,532 209,967 158,175 428,324 349,707 
Delaware102,312 79,895 72,516 63,847 174,828 143,742 
Conventional Permian— — 4,725 320 4,725 320 
Total320,669 271,427 287,208 222,342 607,877 493,769 
(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 reflected ininclude Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.

Undeveloped Acreage Expirations

As of December 31, 2023, the above table.following gross and net undeveloped acres are set to expire over the next five 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
MidlandDelawareTotal
GrossNetGrossNetGrossNet
202410,839 8,805 3 2 10,842 8,807 
20254,143 3,366 — — 4,143 3,366 
20262,862 2,325 428 347 3,290 2,672 
20275 4 — — 5 4 
202859 48 — — 59 48 
Total17,908 14,548 431 349 18,339 14,897 

Title to Properties


As is customary inPrior to the drilling of an oil andor natural gas well, it is the normal practice in our industry we initially conduct only a cursory reviewfor the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations.the well. To the extent title opinions or other investigations reflect title defects on those properties,impacting the development or operation of a producing property, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.defects. We have obtained title opinions on substantially all of
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our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review, or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.


Marketing and Customers


We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2017,2023, four purchasers each accounted for more than 10% of our revenue. For the year ended December 31, 2022, two purchasers each accounted for more than 10% of our revenue. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%);revenue. We do not require collateral and Enterprise Crude Oil LLC (11%). Fordo not believe the year ended December 31, 2016, three purchasers each accounted for more than 10%loss of any single purchaser would materially impact our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasingoperating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. For additional information regarding our customer concentrations, see Note 3—Revenue from us, revenue could declineContracts with Customers in Item 8. Financial Statements and Supplementary Data of this report.

Delivery Commitments

Certain of our operating resultsfirm sales agreements include delivery commitments that specify the delivery of a fixed and financial condition coulddeterminable quantity of oil. We expect our production and reserves will continue to be harmed.

We have entered into an oil purchase agreement with Shell Trading (US) Companythe primary means of fulfilling our future commitments. However, these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment. Beginning in which2023, we agreedbegan purchasing third-party volumes to sell specified quantities of oilfulfill a certain delivery commitment to Shell Trading (US) Company. Our agreement with Shell Trading (US) Company has an initial term of five years ending September 30, 2018. The agreement may also be terminated by Shell Trading (US) Company by written notice to usa pipeline in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated. Our maximum delivery obligation underPermian Basin. For additional information regarding commitments, see Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this agreement is 8,000 gross barrels per day. We have a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity. This decreased contract quantity, if elected, would be effective forreport.


the remainder of the term of the agreement. Shell Trading (US) Company has agreed to pay to us the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If we fail to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, we have agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil that we failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated.


Competition


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

Transportation

During the initial development of our fields we evaluate all gathering and delivery infrastructure in the areas of our production. Currently, a majority of our production in the Midland Basin is transported to purchasers by pipeline. We anticipate that our production in the Delaware Basin transported to purchasers by pipeline will increase to 80% by the end of 2018. During 2018, several oil and saltwater disposal gathering systems were installed. We believe that these gathering systems will help us reduce our lease operating expense and improve our margins on sales in future periods.  

The following table presents the average percentage of produced oil sold by pipeline and the average percentage of produced water connected to saltwater disposals by pipeline:
 Midland Basin Delaware Basin Total
% of produced oil sold by pipeline93% 22% 80%
% of produced water connected to pipeline93% 87% 91%

The following table presents the average cost per Bbl to transport produced oil and water by truck and by pipeline as well as the average savings of transporting produced oil and water by pipeline versus truck:
 Midland Basin Delaware Basin
Oil transportation costs per Bbl:   
Trucked$1.84
 $2.28
Pipeline$1.09
 $1.31
Average savings$0.75
 $0.97
    
Water transportation costs per Bbl:   
Trucked$2.08
 $1.86
Pipeline$0.23
 $0.39
Average savings$1.85
 $1.47




Oil and Natural Gas Leases


The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.50%15% to 25.00%35%, resulting in a net revenue interest to us generally ranging from 75.00%65% to 87.50%85%.


Seasonal Nature of Business


Generally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during the summer months and increases during the winter months. Certain natural gas usersbuyers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. SeasonalIn our exploration and production business, seasonal weather conditions, and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.


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Regulation


Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislationrequirements. Legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.


Environmental Matters and Regulation

Matters. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially and adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.


Waste Handling. The Resource Conservation and Recovery Act, or the RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the Resource Conservation and Recovery Act,RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act,RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in the U.S. Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and natural gas waste. It has until MarchHowever, in April 2019, the EPA concluded that revisions to determine whether any revisionsthe federal regulations for the management of oil and natural gas waste are necessary.not necessary at this time. Any such changes in thesuch laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.




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


Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file
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claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.


Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” or the CWA, the Safe Drinking Water Act, the Oil Pollution Act, or the OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water ActCWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.

The scope of waters regulated under the CWA has fluctuated in recent years. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the USACE,Corps, jointly promulgated final rules redefiningexpanding the scope of waters protected under the Clean Water Act. ToCWA. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the CWA. On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However, on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the decision. These recent actions have provided some clarity. However, to the extent the rule expandsEPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the Clean Water Act’sCWA’s jurisdiction, we or third-party operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Following its promulgation, numerous states and industry groups challenged the rule and, on October 9, 2015, a federal court stayed the rule’s implementation nationwide, pending further action in court. In response to this decision, the EPA and the USACE have resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Further, on February 28, 2017, President Trump signed an executive order directing the relevant executive agencies to review the rules and to initiate rulemaking to rescind or revise them, as appropriate under the stated policies of protecting navigable waters from pollution while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On July 27, 2017, the EPA and the USACE published a proposed rule to rescind the 2015 rules, and, on November 22, 2017, the agencies published a proposed rule to maintain the status quo pending the agencies review of the 2015 rules.


The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “–“—Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.


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




Non-compliance with the Clean Water ActCWA or the Oil Pollution ActOPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.


Air Emissions. The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “–“—Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Additionally, on April 17, 2023, the EPA agreed in a consent decree to issue a proposed rule by December 10, 2024 that
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either revises its emission standards for hazardous air pollutants from oil and natural gas production activities or determines that no revision is necessary. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air ActCAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.


Climate Change. In December 2009,recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022, or the IRA, include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration. Also, the EPA issued an Endangerment Finding that determined thathas proposed ambitious rules to reduce harmful air pollutant emissions, of carbon dioxide, methane and otherincluding greenhouse gases, presentfrom light-, medium-, and heavy-duty vehicles beginning in model year 2027. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA amends the CAA to impose a fee on the emission of methane that exceeds an endangermentapplicable waste emissions threshold from sources required to public health and the environment because, accordingreport their greenhouse gas emissions to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposed changes needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule was published in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emissionincluding those sources in the U.S., including natural gas liquids fractionatorsoffshore and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oilpetroleum and natural gas production and onshore processing, transmission, storagegathering and distribution facilities, which may includeboosting source categories. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025 and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain of our facilities, beginningthresholds established in 2012 for emissions occurring in 2011. In October 2015,the IRA. On January 12, 2024, the EPA amended the greenhouse gas reportingannounced a proposed rule to addimplement the reportingmethane emissions charge. The methane emissions charge could increase our operating costs, which could adversely impact our business, financial condition and cash flows.

The EPA has also finalized a series of greenhouse gas monitoring, reporting and emissions from gatheringcontrol rules for the oil and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gasesindustry, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas capcap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and trade programs. Althoughnatural gas operations. For example, on November 4, 2020, the U.S. Congress has notTexas Railroad Commission adopted such legislation at this time, it may do so innew guidance on when flaring is permissible, requiring operators to submit more specific information to justify the future and many states continueneed to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants,flare or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.vent gas.


At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework forOn April 21, 2021, the parties to cooperateUnited States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and report actionsother world leaders made further commitments to reduce greenhouse gas emissions. However,emissions, including reducing global methane emissions by at least 30% by 2030 from 2020 levels. More than 150 countries have now signed on June 1, 2017, President Trump announced thatto this pledge. Most recently, at the 28th Conference of the Parties in the United States would withdrawArab Emirates, world leaders agreed to transition away from the Paris Agreement,fossil fuels in a just, orderly and begin negotiationsequitable manner and to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect


one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement.triple renewables and double energy efficiency globally by 2030. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth insupport the international accord.climate commitments.


Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.


In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Regulation of Hydraulic Fracturing

Fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of the U.S. Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing
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with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.


In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, onOn June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.


On August 16, 2012, the EPA published final regulations under the federal Clean Air ActCAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will


likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, on August 13, 2020, in a March 28, 2017response to an executive order by former President Trump directedto review and revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to review the 2016 regulationsease regulatory burdens, including rescinding standards applicable to transmission or storage segments and if appropriate, to initiateeliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe developmentjoint resolution of the nation’s energy resources, while atU.S. Congress disapproving the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017,2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on December 2, 2023, the EPA publishedannounced a proposedfinal rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. These new standards, to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards,extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.


Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy the U.S. Geological Survey, and the U.S. Government Accountability Office,Department of the Interior have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.


Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments
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designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits and temporarily suspend operations for waste disposal wells. For example, in September 2021, the Texas Railroad Commission curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has subsequently suspended some permits there and expanded the restrictions to other areas. In addition, the Texas Railroad Commission has imposed monitoring and reporting requirements for any new disposal well permitted in the Permian Basin. These restrictions on use of produced water, a moratorium on new produced water disposal wells, and additional monitoring and reporting requirements could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling and completion activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.


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


Endangered Species. The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species, such as the recently listed lesser prairie chicken, are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. However, the designation of previously unprotected species, such as the dunes sagebrush lizard (proposed as endangered on July 3, 2023), in areas where we operate as threatened or endangered could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.

Other Regulation of the Oil and Natural Gas Industry

Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the


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


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


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


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

following; the location of wells;

the method of drilling and casing wells;

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

the rates of production or “allowables”;

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

the plugging and abandoning of wells; and

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


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


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


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




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

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

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


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


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


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Safety and Maintenance Regulation. In our midstream operations, we are subject to regulation by the U.S. Department of Transportation, or DOT, underthe Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including natural gas liquids and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

We are also subject to the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $266,015 and $2,660,135, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures, and, on August 24, 2022, PHMSA published a final rule strengthening integrity management requirements for onshore gas transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events. Further, on May 18, 2023, PHMSA published a proposed rule to reduce methane emissions from new and existing gas pipelines, underground natural gas storage facilities, and liquefied natural gas facilities. These requirements and related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. For example, on December 17, 2019, the Texas Railroad Commission adopted rules requiring that operators of gathering lines take 'appropriate' actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Rattler LLC and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified
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thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.

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


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


Operational Hazards and Insurance


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


In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physical damage protection, control of well protection for selectedall wells,


comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date)date and occurrence-based coverage for sudden, accidental releases), excess umbrella liability and other coverage.


Our insurance is subject to exclusioncertain exclusions and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See ItemItem 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Operating hazardsRisk Factors of this report for additional information regarding operating hazard and uninsured risks may result in substantial losses and could prevent us from realizing profits.”risks.


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


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


Employees
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Human Capital

We have developed a culture grounded upon the solid foundation of our core values—leadership, integrity, excellence, people and teamwork—that are adhered to throughout our company. We set a high bar for all of our employees in terms of how they operate and interact, both within the office and out in the field. We challenge them to identify new ways to foster a better future for themselves and for us. Our board of directors, through its Safety, Sustainability and Corporate Responsibility Committee, which we refer to as the SS&CR Committee, provides an important oversight of our human capital management strategy, including diversity, equity and inclusion. The SS&CR Committee receives regular updates from our executive leadership, senior management and third-party consultants on human capital trends and other key human capital matters impacting our business.

As of December 31, 2017,2023, we had approximately 2511,023 full time employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hireutilize independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full timefull-time employees.


Diversity, Inclusion, Recruiting and Retention

Equal employment opportunity is one of our core tenets and, as such, our employment decisions are based on merit, qualifications, competencies and contributions. We actively seek to attract and retain an increasingly diverse workforce and continue to cultivate our respectful work environment. We value the perspectives, experiences and ideas contributed by our employees from a diverse range of ethnic, cultural and ideological backgrounds. Over 28% of our employees are women and over 35% of our employees self-identify as ethnic minorities as of December 31, 2023. We disclosed our 2022 Equal Employment Opportunity (EEO-1) data as of December 31, 2022 in our 2023 Corporate Sustainability Report in an effort to provide additional transparency into the Company’s workforce demographics.

In 2023, we took various actions to increase the diversity of job applicants and expand our recruitment efforts, particularly in our college recruitment and internship programs. We collaborated with several student organizations to reinforce this inclusive initiative, which will continue in the future. In addition, we have focused on recruiting experienced hires to target and retain top industry talent. We have historically had a low annual attrition rate, representing approximately 14% in 2023, despite the challenging labor market and increased competition for talent impacted by the potential economic downturn and the high inflationary environment. We believe that our low attrition rate is in part a result of our corporate culture focused on diversity and inclusion, teamwork and commitment to employee development and career advancement discussed in more detail below.

Health and Safety

Protecting employees, the public and the environment is a top priority in our operations and in the way we manage our assets. We are focused on minimizing the risk of workplace incidents and preparing for emergencies as an ingrained element of our corporate responsibility. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.

We have committed to reduce injuries and fatalities in our business and are focused on safety culture improvements, safety leadership actions and human performance principles. We are requiring our operational employees and independent contractors and their employees to go through orientation and training aligned with the International Association of Oil and Gas Producers Life Saving Rules, a program that also meets the operational safety requirements adopted by the American Petroleum Institute. We also involve employees from all operational levels in our safety program to provide input and suggested improvements to the overall safety program, recommend preventative measures based on reviewing vehicle and personnel incidents, safety and environmental audits at operational locations and participate in the audit and oversight of the Diamondback Hazard Communication Program.

From 2019 through 2023, we had no employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled three in 2023, down from six in 2022. Our employee total recordable incident rate (TRIR) was 0.30 in 2023 down from 0.68 in 2022, and lost-time incident rate (LTIR) was 0.10 in 2023 down from 0.23 in 2022. At December 31, 2023, we have a short term goal of maintaining an employee TRIR of 0.25 or less.

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Training and Development

We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2023 included a wide array of topics in addition to extensive safety and other compliance training sessions. Additionally, our people undergo training and education each year on regulatory compliance, industry standards and innovative opportunities to effectively manage the challenges of developing our resources. We have also implemented development programs that are designed to build leadership capabilities at all levels.

Our Facilities


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


Availability of Company Reports


Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Form 10-KAnnual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.




ITEM 1A. RISK FACTORS


The nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Item 1. “Business and Properties”Properties,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to the Companyus or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.


The following is a summary of the principal risks that could adversely affect our business, operations and financial results:

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


•Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas have in the past adversely affected, and may in the futurecontinue to adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.

•Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

the domestic and foreign supply of oil and natural gas;

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

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

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

the price and quantity of foreign imports;

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

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

speculative trading in crude oil and natural gas derivative contracts;

the level of consumer product demand;

weather conditions•The IRA and other natural disasters;

risks associated with operating drilling rigs;

technological advances affecting energy consumption;

relating to climate change could accelerate the price and availability of alternative fuels;

domestic and foreign governmental regulations and taxes;

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

the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficulttransition to predict future oil and natural gas price movements with any certainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $26.19 per barrel, or Bbl, in February 2016


to a high of $110.62 per Bbl in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. During 2017, WTI prices ranged from $42.48 to $60.46 per Bblcarbon economy and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On January 29, 2018, the WTI posted price for crude oil was $65.71 per Bbl and the Henry Hub spot market price of natural gas was $3.60 per MMBtu, representing increases of 9% and 3%, respectively, from the high of $60.46 per Bbl of oil and $3.71 per MMBtu for natural gas during 2017. If the prices of oil and natural gas decline,could impose new costs on our operations financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.

Concerns over general economic, business or industry conditions may have a material and adverse effect on our results of operations, liquidityus.
•Climate change-related regulations, policies and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growthinitiatives may have another adverse impact on global financial markets and commodity prices. If the economic climate in the United Stateseffects, such as a greater potential for governmental investigations or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.litigation.

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

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

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

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2017, our total capital expenditures, including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $3.2 billion. Our 2018 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $1.3 billion to $1.5 billion, representing an increase of 60% over our 2017 capital budget. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and the senior notes.

We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

our proved reserves;

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



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

our ability to acquire, locate and produce economically new reserves; and

our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2018 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

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

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

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

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

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.



Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed and pending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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

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

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

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition.

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

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

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through December 31, 2017, we drilled a total of 412 gross horizontal wells and 262 gross vertical wells and participated in an additional 61 gross horizontal wells and 18 gross vertical non-operated wells, of which 670 wells were completed as producing wells and 83 wells were in various stages of completion. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.



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

At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage. As of December 31, 2017, only 168 of our gross identified potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 873 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. Through December 31, 2017, we are the operator of or have participated in a total of 466 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2017, we had leases representing 22,913 net acres expiring in 2018, 19,670 net acres expiring in 2019, 20,219 net acres expiring in 2020, 719 net acres expiring in 2021 and no net acres expiring in 2022. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2018, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

We have entered into fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options and may in the future enter into forward sale contracts or additional fixed price swap, fixed price basis swap derivatives or costless collars for a portion of our production. Although we have hedged a portion of our estimated 2018 and 2019 production, we may still be adversely affected by continuing and prolonged declines in the price of oil.

We use fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our oil and natural gas sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. Under the Company’s costless collar contracts, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. The counterparty is required to make a payment


to us if the settlement price for any settlement period is less than the put option price. These contracts and any future economic hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase.

As of December 31, 2017, we had the following commodity contracts in place covering NYMEX WTI crude oil, Brent crude oil and NYMEX Henry Hub natural gas for the production period of January 2018 through December 2018:

crude oil swap contracts priced at a weighted average price of $51.10 WTI for 9,761,000 aggregate Bbls;

crude oil swap contracts priced at a weighted average price of $54.89 Brent for 1,830,000 aggregate Bbls;

crude oil basis swap contracts priced at a weighted average price of $0.88 for 5,475,000 aggregate Bbls for the spread between the WTI Midland price and the WTI Cushing price;

natural gas swap contracts priced at a weighted average price of $3.14 for 7,750,000 aggregate MMBtu; and

crude oil costless collars contracts with a floor price of $47.00 for 540,000 aggregate Bbls and a ceiling price of $56.34 for 270,000 aggregate Bbls.

We have crude oil swap contracts priced at a weighted average price of $49.82 WTI for 1,095,000 aggregate Bbls with a production period of January 2019 through December 2019. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not be able to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

Our derivative transactions expose us to counterparty credit risk.

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

•If production from our Permian Basin acreage decreases, due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to the counterparty and may have an adverse effect onadversely affect our operations.

We are a party to an agreement with Shell Trading (US) Company under which we are obligated to deliver specified quantities of oil to Shell Trading (US) Company. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to decrease the contract quantity by not more than 20% of the then-current quantity. This decreased quantity, if elected, would be effective for the remainder of the term of the agreement. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under the oil purchase agreement, which may result in deficiency payments to the counterparty and may have an adverse effect on our operations.

•The inability of one or more of our customers to meet their obligations, or loss of one or more of our significant purchasers, may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $73.0 million at December 31, 2017) and receivables from purchasers of our oil and natural gas production (approximately $158.6 million at December 31, 2017). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.


Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

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

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We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2017, 2016 and 2015 was $321.9 million, $176.4 million and $216.1 million, respectively.

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

Impairments on proved oil and natural gas properties of $245.5 million and $814.8 million were recorded for the years ended December 31, 2016 and 2015, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method of accounting for oil and natural gas properties” for a more detailed description of our method of accounting.

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

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves as of December 31, 2017, 2016 and 2015 (which include those attributable to Viper)•We are based on reports prepared by Ryder Scott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The estimates of reserves as of December 31, 2017, 2016 and 2015 included in this report 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 December 31, 2017, 2016 and 2015, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.



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

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities–Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe because they have become uneconomic or otherwise.

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

Approximately 37.8% of our total estimated proved reserves as of December 31, 2017, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

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

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

In addition to the geographic concentration of our producing properties described above, as of December 31, 2017, all of our proved reserves were attributable to the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.



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

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.

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

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

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

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

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

Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations to continue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

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



Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.

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

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

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

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

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

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilitiescontrol, or rigs, equipment, raw materials, oil services or personnel are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.



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

Our oilexpensive and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitationsimpose restrictions on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Item 1. “Business–Regulation” for a description of certain laws and regulations that affect us.

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

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office,


have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business and Properties–Regulation–Regulation of Hydraulic Fracturing.” We use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

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

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

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

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

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


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

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

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act, or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The Commodities Futures Trading Commission’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the Commodities Futures Trading Commission to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the Commodities Futures Trading Commission has indicated that it intends to appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the Commodities Futures Trading Commission will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Recently enacted •U.S. tax legislation, as well as future U.S. tax legislationsincluding recently adopted IRA, may adverselynegatively affect ourbusiness, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Ac, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code. Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and we cannot predict with certainty the resulting impact its enactment will have on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional


regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.

In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.

Regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject to certain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”
At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. The Agreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of our products and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully


insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposal wells.
We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by owned disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

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

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes.  Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

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



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

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

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

unusual or unexpected geological formations;

loss of drilling fluid circulation;

title problems;

facility or equipment malfunctions;

unexpected operational events;

shortages or delivery delays of equipment and services;

compliance with environmental and other governmental requirements; and

adverse weather conditions.

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

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

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

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices


for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.

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

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

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

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

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

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

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


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

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

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

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We recorded stock-based compensation expense in 2017, 2016 and 2015, and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, for the years ended December 31, 2017, 2016 and 2015 we incurred $34.2 million, $33.5 million and $24.6 million, respectively, of stock based compensation expense, of which we capitalized $8.6 million, $7.1 million and $6.0 million respectively, pursuant to the full cost method of accounting for oil and natural gas properties. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expenses could adversely


affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

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

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

•A terrorist attack or armed conflict could harm our business.

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

We are subject to cyber security risks. •A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.


The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.

Risks Related to Our Indebtedness


•Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notesour indebtedness, and we and our other indebtedness.

As of December 31, 2017, we had total long-term debt of $1.5 billion, including $1.0 billion outstanding under the 2024 senior notes and 2025 senior notes, and we had an unused borrowing base availability of $603.0 million under our revolving credit facility. On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025, which we refersubsidiaries may be able to as the new 2025 notes, asincur substantial additional notes under our existing indenture, and repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes. Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, we had total long-term debt of $1.39 billion (including $1.3 billion attributable to all of our outstanding senior notes), our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility. As of December 31, 2017, Viper, one of our subsidiaries, had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. We mayindebtedness in the future incurfuture.
•Implementing our capital programs may require, under some circumstances, an increase in our total leverage through additional debt issuances, and any significant additional indebtednessreduction in availability under our revolving credit facility or inability to otherwise in order to make acquisitions, to developobtain financing for our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:



our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder;

a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the funds available to us for operations and other purposes;

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

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

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

our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;

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

a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;

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

we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.

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

•Restrictive covenants in certain of our revolving credit facility, the indentures governing the senior notesexisting and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility and the indentures governing our outstanding senior notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things:

incur or guarantee additional indebtedness;

make certain investments;

create additional liens;

sell or transfer assets;

issue preferred stock;

merge or consolidate with another entity;

pay dividends or make other distributions;

designate certain of•We depend on our subsidiaries as unrestricted subsidiaries;

create unrestricted subsidiaries;



engage in transactions with affiliates; and

enter into certain swap agreements.

In connection with the closing of Viper’s initial public offering on June 23, 2014, we entered into an amendment to our revolving credit facility, which modified certain provisions of our revolving credit facility to allow us, among other things, to designate one or more of our subsidiaries as “unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under the amended revolving credit facility, we designated Viper, the general partner and Viper’s subsidiary as unrestricted subsidiaries, and upon such designation, they were automatically released from any and all obligations under the amended revolving credit facility, including the related guaranty, and all liens on the assets of, and the equity interests in, Viper, the general partner and Viper’s subsidiary under the amended revolving credit facility were automatically released. Further Viper, the general partner and Viper’s subsidiaries, Viper Energy Partners LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC), are designated as unrestricted subsidiaries under the indentures governing our outstanding senior notes.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indentures governing our senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interestfor dividends and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.payments.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

Availability under our revolving credit facility is currently subject to a borrowing base of $1.8 billion, of which we have elected a commitment amount of $1.0 billion. The borrowing base is subject to scheduled annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. On January 29, 2018, we repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes. Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility. We expect to borrow under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more


alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2017, our borrowing base under our revolving credit facility was set at $1.8 billion, of which we have elected a commitment amount of $1.0 billion and we had $397.0 million outstanding borrowings under this facility. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. Further, the indentures governing the senior notes allow us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing the senior notes also allow us to incur certain other additional secured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

•If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

•Borrowings under our and Viper’sViper LLC’s revolving credit facilities expose us to interest rate risk.


Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. Viper’s weighted average interest rate on borrowings from its revolving credit facility was 3.19% during the year ended December 31, 2017. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.



Risks Related to Our Common Stock


•The corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
•The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors, and there is no guarantee that we will pay any dividends on or repurchases of our common stock in the future or at levels anticipated by our stockholders.
•A change of control could limit our use of net operating losses.
•We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
•Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

Risks Related to the Pending Endeavor Acquisition

•Our ability to complete the Endeavor Acquisition is subject to various closing conditions, including approval by our stockholders and regulatory clearance, which may impose conditions that could adversely affect us or cause the Endeavor Acquisition not to be completed.
•The termination of the Merger Agreement could negatively impact our business or result in our having to pay a termination fee.
•Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business.
•Combining our business with Endeavor’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Endeavor Acquisition.
•We also expect to incur significant additional indebtedness in connection with the Endeavor Acquisition, which indebtedness may limit our operating or financial flexibility relative to our current position and make it difficult to satisfy our obligations with respect to our other indebtedness.
•The market value of our common stock could decline if large amounts of our common stock are sold following the Endeavor Acquisition.
•Following the closing of the Endeavor Acquisition, the Endeavor Stockholders will have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.

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

Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia; the potential impact of the war in Ukraine and the Israel-Hamas War on the global energy markets and macroeconomic conditions; the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; the ability of members of the OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes, including the Biden Administration’s energy and environmental policies; global or national health concerns, including the outbreak of pandemic or contagious disease; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions. Our results of operations may also be adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2023, 2022 and 2021, NYMEX WTI prices ranged from $47.62 to $123.70 per Bbl and the NYMEX Henry Hub price of natural gas ranged from $1.99 to $9.68 per MMBtu. If the prices of oil and natural gas decline, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

We expect to maintain our fourth quarter 2023 production levels in 2024. We cannot reasonably predict whether production levels will remain at current levels or the full extent of the impact of the events above and any subsequent recovery may have on our industry and our business.

If commodity prices fall below current levels, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows will be adversely impacted. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to conduct additional exploration and development activities.

Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases andmayexpose us to other risks, including counterparty credit risk.

We use commodity price derivatives, including swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil, natural gas liquids and natural gas sales. Currently, we have hedged a portion of our estimated 2024 and 2025 production. To the extent that the prices of oil, natural gas liquids and natural gas remain at current levels or decline further, we may not be able to economically hedge additional future production at the same level as our current commodity price derivatives, and our results of operations and financial condition may be negatively impacted. While these commodity price derivatives are intended to mitigate risk from commodity price volatility, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas liquids and natural gas above the price levels of the commodity price derivatives used to manage price risk.

At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.

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For additional information regarding our outstanding derivative contracts as of December 31, 2023, see Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report.

The IRA and other risks relating to climate change could accelerate the transition to a low carbon economy and could impose new costs on our operations that may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in; (i) the enactment of climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures; (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology); (iii) increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and (iv) development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, the oil and natural gas that we produce and sell, which would likely have a material adverse impact on us.

If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy. The enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. For example, the Infrastructure Investment and Jobs Act and the IRA include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration. Also, the EPA has proposed ambitious rules to reduce harmful air pollutant emissions, including greenhouse gases, from light-, medium-, and heavy-duty vehicles beginning in model year 2027. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we produce and sell and adversely impact our business. In addition, the IRA imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge, which could increase our operating costs and thereby adversely impact our business, financial condition and cash flows.

In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, any of these developments may also create reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. For example, a number of prominent investors have publicly announced their intention to no longer invest in the oil and gas sector in response to concerns related to climate change, and other financial institutions and investors may decide to do likewise in the future. If financial institutions and other investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased costs.

For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, please see the section entitled Items 1 and 2. Business and Properties—Regulation—Climate Change of this report.

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Continuing political and social concerns relating to climate change may result in significant litigation and related expenses.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect us. For example, shareholder activism has recently been increasing in our industry, and shareholders may attempt to effect changes to our business or governance to deal with climate change-related issues, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise, which may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages.

Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions in our operations, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and results of operations.

Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.

We have developed, and will continue to develop, targets related to our environmental, social and governance (“ESG”) initiatives, including our emissions reduction targets and strategy. Statements in this and other reports we file with the SEC and other public statements related to these initiatives reflect our current plans and expectations and are not a guarantee the targets will be achieved or achieved on the currently anticipated timeline. Our ability to achieve our ESG targets, including emissions reductions, is subject to numerous factors and conditions, some of which are outside of our control, and failure to achieve our announced targets or comply with ethical, environmental or other standards, including reporting standards, may expose us to government enforcement actions or private litigation and adversely impact our business. Further, our continuing efforts to research, establish, accomplish and accurately report on these targets may create additional operational risks and expenses and expose us to reputational, legal and other risks.

ESG expectations, including both the matters in focus and the management of such matters, continue to evolve rapidly. For example, in addition to climate change, there is increasing attention on topics such as diversity and inclusion, human rights, and human and natural capital, in companies’ own operations as well as their supply chains. In addition, perspectives on the efficacy of ESG considerations continue to evolve, and we cannot currently predict how regulators’, investors’ and other stakeholders’ views on ESG matters may affect the regulatory and investment landscape and affect our business, financial condition, and results of operations. If we do not, or are perceived to not, adapt or comply with investor or stakeholder expectations and standards on ESG matters, we may suffer from reputational damage and our business, financial condition and results of operations could be materially and adversely affected. Any reputational damage associated with ESG factors may also adversely impact our ability to recruit and retain employees and customers.

In March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks and other information. To the extent this rule is finalized as proposed, we and/or our customers could incur increased costs related to the assessment and disclosure of climate-related information. Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors.

Investor and regulatory focus on ESG matters continues to increase. If our ESG initiatives do not meet our investors’ or other stakeholders’ evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation, contractual, employment and other business relationships may be adversely impacted.

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

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

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

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

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

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2023, our total capital expenditures, including expenditures for drilling, completion, infrastructure and additions to midstream assets, were approximately $2.7 billion. Our 2024 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately $2.30 billion to $2.55 billion, representing a decrease of 10% from our 2023 capital expenditures. Since completing our initial public offering in October 2012, we have financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds from public offerings of our common stock and our senior notes.

We intend to finance our future capital expenditures with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2024 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

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

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

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding and development costs for additional reserves could also increase.

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

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs, and potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, including title defects or environmental issues, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

Any of these factors could have a material adverse effect on our financial condition and results of operations. Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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

Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs.

As of December 31, 2023, we have approximately 7,905 gross (5,826 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $50.00 per Bbl WTI. As of December 31, 2023, only 802 of our gross identified economic potential horizontal drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, as of December 31, 2023, we have identified approximately 2,561 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations,
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our drilling success rate may decline and materially harm our business. Through December 31, 2023, we are the operator of, have participated in, or have acquired working interest in a total of 3,356 horizontal producing wells completed on our acreage. We cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

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

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Any non-renewal or other loss of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.

We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to our counterparties. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to reduced developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.

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

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $122 million at December 31, 2023) and receivables from purchasers of our oil and natural gas production (approximately $654 million at December 31, 2023). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See Items 1 and 2. Business and Properties—Marketing and Customers of this report for additional information regarding these customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic and other conditions. We do not require our customers to post collateral. Under certain circumstances, the revenue due to them can be offset by any unpaid receivables. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

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

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment.

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

No impairments were recorded on our proved oil and natural gas properties for the years ended December 31, 2023, 2022 and 2021. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Oil and Natural Gas Accounting and Reserves of this report. If the prices of oil and natural gas decline, we may be required to further write-down the value of our oil and natural gas properties in the future, which could negatively affect our results of operations.

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

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

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

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil reserves.

The present value of future net cash flows from our proved reserves, or standardized measure may not represent the current market value of our estimated proved oil reserves. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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

Approximately 31% of our total estimated proved reserves as of December 31, 2023, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling and completion operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

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

Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities.

Extreme regional weather events may occur that can affect our suppliers or customers, which could adversely affect us. For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our production) to be curtailed or shut in or (in the case of natural gas) flared. Climate change may also increase the frequency and severity of significant weather events over time. Further, any increase in flaring of our natural gas production due to weather-related events or otherwise could make it difficult for us to achieve our publicly-announced sustainability and emissions reduction targets, which could expose us to reputational risks and adversely impact our contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us and our production volumes (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2023, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

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

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including those discussed. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See Items 1 and 2. Business and Properties—Marketing and Customers of this report for additional information regarding these customers. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.

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

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

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

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Also, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. In October 2023, the Commission announced draft amendments to its water protection rules to, among other things, encourage waste recycling. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Recent regulatory restrictions on the disposal of produced water and additional monitoring and reporting requirements related to existing and new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.

In September 2021, the Texas Railroad Commission curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. The Texas Railroad Commission has since adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These restrictions and additional monitoring and reporting requirements related to existing and new produced water and produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

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

Our operations involve developing and utilizing the latest drilling and completion techniques. Risks that we face while drilling include, but are not limited to, spacing of wells to maximize economic return; landing our well bore in the desired drilling zone; staying in the desired drilling zone while drilling horizontally through the formation; running our casing the entire length of the well bore; and being able to run tools and other equipment consistently through the horizontal well bore.

Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages; run tools the entire length of the well bore during completion operations; successfully clean out the well bore after completion of the final fracture stimulation stage; and prevent unintentional communication with other wells.

Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

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

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

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. We do not control third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

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

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Items 1 and 2. Business and Properties—Regulation of this report for a detailed description of certain laws and regulations that affect us.

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

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered, such as the recent designation of lesser prairie chickens in southwestern Texas as endangered, could cause us to incur increased costs arising
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from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act established federal oversight of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act required the Commodity Futures Trading Commission (CFTC), the SEC, and certain federal regulators of financial institutions (Prudential Regulators), to adopt rules or regulations implementing the Dodd-Frank Act. The Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued a number of rules, including rules requiring clearing of certain swaps through registered clearing facilities (Mandatory Clearing Rule), requiring the posting of collateral for uncleared swaps (Margin Rule) and imposing position limits (Position Limit Rule). There are exceptions, subject to meeting certain filing, recordkeeping and reporting requirements, to the Mandatory Clearing Rule, the Margin Rule and the Position Limit Rule.

We qualify for the “end user” exception to the Mandatory Clearing Rule and the “non-financial end user” exception to the Margin Rule and we believe that the majority, if not all, of our hedging activities qualify for the “bona fide hedging transaction or position” exception to the Position Limit Rule. We intend to satisfy the applicable filing, recordkeeping and reporting requirements to use these exceptions, so we do not expect to be directly affected by any of such rules. However, most if not all of our swap counterparties will be subject to mandatory clearing and collateral requirements in connection with their hedging activities with other counterparties that do not qualify for exceptions to these rules, which could significantly increase the cost of our derivative contracts or reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business.

In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations (collectively, Foreign Regulations), which may apply to our transactions with counterparties subject to such Foreign Regulations (Foreign Counterparties). The Foreign Regulations, the Dodd-Frank Act, the rules which have been adopted and not vacated and other regulations could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act, the Foreign Regulations or other regulations, our results of operations and cash flows may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

U.S. tax legislation may adversely affect ourbusiness, results of operations, financial condition and cash flow.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

On August 16, 2022, President Biden signed into law the IRA, which, among other changes, imposes a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock repurchases for tax years beginning after December 31, 2022. If we are or become subject to CAMT, our cash obligations for U.S. federal income taxes could be significantly accelerated.To the extent the 1% excise tax applies to repurchases of shares under our common stock repurchase program, the number of shares we repurchase and our cash flow may be affected.

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The U.S. Treasury Department, the Internal Revenue Service and other standard-setting bodies are expected to issue guidance on how the CAMT, stock buyback excise tax and other provisions of the IRA will be applied or otherwise administered that may differ from our interpretations. We continue to evaluate the IRA and its effect on our financial results and operating cash flow.

We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

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

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

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

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

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

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

Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

We own interests in certain pipeline projects and other joint ventures, and we may in the future enter into additional joint ventures, and our control of such entities is limited by provisions of the governing documents of such entities and by our percentage ownership in such entities.

We have ownership interests in several joint ventures, including the EPIC, Wink to Webster, BANGL, WTG and Deep Blue joint ventures, and we may enter into other similar arrangements in the future. While we own equity interests and have certain voting rights with respect to our ownership interest, we do not control our joint ventures. We have limited ability to influence the business decisions of these entities, and it may therefore be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our or the relevant joint venture’s best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control. In addition, our joint venture partners may not satisfy their financial obligations to the joint venture and may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture.

We are also unable to control the amount of cash we receive from the operation of these entities. Further, certain of these joint ventures have incurred substantial debt and servicing such debt or complying with debt covenants may limit the ability of the joint ventures to make distributions to us and the other joint venture partners. These joint ventures also have internal control environments independent of our oversight and review. If our joint venture partners have control deficiencies in their accounting or financial reporting environments, it may result in inaccuracies in the reporting for our percentage of the financial results of the joint venture.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

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A terrorist attack or armed conflict could harm our business.

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

Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.

We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.

We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

As an exploration and production company, we rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices, remote communications and work-from-home or hybrid work practices that evolved in response to the COVID-19 pandemic and became a common business practice thereafter.

Risks from cybersecurity threats have not materially affected, and are not currently anticipated to materially affect our company, including our business strategy, results of operations and financial condition. However, our systems and networks, and those of our vendors, service providers and other third party providers, may become the target of cybersecurity attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; cyber or phishing-attacks; ransomware; attempts to gain unauthorized access to our data and systems; and other electronic security breaches. If any of these security breaches were to occur, we could suffer disruptions to our normal operations, including our exploration, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources, or reduce our competitive advantage over other companies; data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident; data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges; unauthorized access to, and release of, personal information of our employees, vendors, service providers or other third parties, which could expose us to allegations that we did not sufficiently protect such information; a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations; a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or other facilities, which could result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues; a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues; a deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory enforcement actions, fines or penalties; a cybersecurity attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and a cybersecurity attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards.

We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threat. We have engaged third-party consultants to conduct penetration testing and risk assessments. Our
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cybersecurity governance program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration. Such measures, however, cannot entirely eliminate cybersecurity threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Risks Related to Our Indebtedness

References in this section to “us, “we” or “our” shall mean Diamondback Energy, Inc. and Diamondback E&P LLC, collectively, unless otherwise specified.

Implementing our capital programs may require, under some circumstances, an increase in our total leverage through additional debt issuances, and any significant reduction in availability under our revolving credit facility or inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.

We have historically relied on availability under our revolving credit facility to fund a portion of our capital expenditures. We expect that we will continue to fund a portion of our capital expenditures with borrowings under the revolving credit facility, cash flow from operations and the proceeds from debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from debt or equity offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. Instead, we may be required or choose to finance our capital expenditures through additional debt issuances, which would increase our total amount of debt outstanding. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could limit our ability to fund our drilling activities and acquisitions or otherwise finance the capital expenditures necessary to replace our reserves.

Restrictive covenants in certain of our existing and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates. A breach of any of these restrictive covenants could result in default under the applicable debt instrument.

We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our and our subsidiaries’ debt instruments. As an example, our revolving credit facility requires us to maintain a total net debt to capitalization ratio. The requirement that we and our subsidiaries comply with these provisions may materially adversely affect our and our subsidiaries ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If a default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If the indebtedness under our revolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. If we are unable to generate sufficient cash flow to service our debt, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining
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additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

We depend on our subsidiaries for dividends and other payments.

As a holding company, we depend on our subsidiaries for dividends and other payments. We are a legal entity separate and distinct from our operating subsidiaries. There are statutory and regulatory limitations on the payment of dividends. If our subsidiaries are unable to make dividend payments to us and sufficient cash or liquidity is not otherwise available, we may not be able to make dividend payments to our stockholders or principal and interest payments on our outstanding indebtedness.

We and our subsidiaries may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our and our subsidiaries’ revolving credit facilities and the indentures restrict, but in each case do not completely prohibit, us from doing so. Further, the indentures governing our and our subsidiaries’ notes allow us to issue additional notes, incur certain other additional debt and to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Borrowings under our and Viper LLC’s revolving credit facilities expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our and Viper LLC’s revolving credit facilities. The terms of our and Viper LLC’s revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to the secured overnight financing rate (“SOFR”). SOFR tends to fluctuate based on multiple factors, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks and general economic conditions. From time to time, we use interest rate swaps to reduce interest rate exposure with respect to our fixed and/or floating rate debt. The weighted average interest rate on borrowings under our revolving credit facility was 6.31% during the year ended December 31, 2023. Viper LLC’s weighted average interest rate on borrowings from its revolving credit facility was 7.41% during the year ended December 31, 2023. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

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Risks Related to Our Common Stock

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


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

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

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

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


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


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

In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests.

If the pricerepurchases of our common stock fluctuates significantly, your investment could lose value.

Although our common stock is listed on the Nasdaq Select Global Market, we cannot assure you that an active public market will continue for our common stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

our quarterly or annual operating results;

changes in our earnings estimates;

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

additions or departures of key personnel;

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

our failure to achieve operating results consistent with securities analysts’ projections;
changes in industry, general market or economic conditions; and

announcements of legislative or regulatory changes.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur


without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

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

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital through the sale of additional common or preferred stock. Except for any shares purchased by our affiliates, all of the shares of common stock sold in our initial public offering and our subsequent equity offerings are freely tradable. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

The declaration of dividends on our common stock iseach within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payable quarterly beginning with the first quarter of 2018.
The decision to pay this first dividend or any future base and variable dividends however, is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, whether base or variable, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.

In September 2021, our board of directors approved a stock repurchase program to acquire up to $2.0 billion of our outstanding common stock, and on July 28, 2022, approved an increase in the repurchase program to $4.0 billion. We may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. Through December 31, 2023, approximately $2.4 billion has been repurchased through the repurchase program. Even though this program is in place, we may not repurchase any shares through the program and any such repurchases are completely within the discretion of our board of directors. In addition, the stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. Any elimination of, or reduction in, the Company’s base or variable dividend or common stock repurchase program could adversely affect the total return of an investment in and have a material adverse effect on the market price of our common stock.

Beginning in the first quarter of 2024, our board of directors approved a reduction to our return of capital commitment to at least 50% from 75% of free cash flow to be distributed quarterly to our stockholders in the primary form of a base dividend with additional return of capital expected to be in the form of a variable dividend and through our stock repurchase program. The amount of cash available to return to our stockholders, if any, can vary significantly from quarter to quarter for a number of reasons, including commodity prices, liquidity, debt levels, capital resources and other factors. The price of our common stock may deteriorate if we are unable to meet investor expectations with respect to the timing and amount of our return of capital commitment to our stockholders, and such deterioration may be material.

A change of control could limit our use of net operating losses.losses and certain other tax attributes.


As of December 31, 2017, we had a net operating loss, or NOL, carry forward of approximately $357.0 million for federal income tax purposes. If we were to experience an “ownership change,” as determined underUnder Section 382 of the Internal Revenue Code ourof 1986, as amended (the “Code”), a corporation that experiences an “ownership change” (as defined in the Code) may be subject to limitations on its ability to offset taxable income arising after the ownership change with NOLsnet operating losses (“NOLs”) or tax credits generated prior to the ownership change would be limited, possibly substantially.change. In general, an ownership change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occuroccurs if there is a cumulative increase in ourthe ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period. An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs or tax credits that could be utilized to offset taxable income in any future taxable year. The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred

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If securities or industry analysts doto as the long-term tax-exempt rate, periodically promulgated by the IRS. This limitation, however, may be significantly increased if there is “net unrealized built-in gain” in the assets of the corporation undergoing the ownership change.

As of December 31, 2023, we had an NOL carryforward of approximately $590 million and tax credits of $4 million for U.S. federal income tax purposes, principally consisting of tax attributes acquired from QEP and Rattler. As a result of ownership changes for Diamondback Energy, Inc., QEP and Rattler, which occurred in connection with the acquisition of QEP and the Rattler Merger, our NOLs and other carryforwards, including those acquired from QEP and Rattler, are subject to an annual limitation under Section 382 of the Code. However, we have determined that our fair market value and our net unrealized built-in gain position resulted in a significant increase in our Section 382 limits. Accordingly, we believe that the application of Section 382 of the Code as a result of these ownership changes will not publish research or reports abouthave a material adverse effect on our business, if they adversely change their recommendations regardingability to utilize our NOLs and credits.

Future changes in our stock or if our operating results do not meet their expectations, our stock priceownership, however, could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibilityresult in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or morean additional ownership change under Section 382 of the analysts who coverCode. Any such ownership change may limit our company downgrade our stockability to offset taxable income arising after such an ownership change with NOLs or if our operating results do not meet their expectations, our stock price could decline.other tax attributes generated prior to such an ownership change, possibly substantially.


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




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


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

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

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

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

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

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

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


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


Risks Related to the pending Endeavor Acquisition

Our ability to complete the Endeavor Acquisition is subject to various closing conditions, including approval by our stockholders and regulatory clearance, which may impose conditions that could adversely affect us or cause the Endeavor Acquisition not to be completed.

On February 11, 2024, we entered into the Merger Agreement to acquire Endeavor. The Endeavor Acquisition is subject to a number of conditions to closing as specified in the Merger Agreement. These closing conditions include, among others, (i) the approval of the issuance of our common stock in the first merger by our stockholders; (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (iii) the absence of any injunction, order, decree or law preventing, prohibiting or making illegal the consummation of the first merger; (iv) the authorization for listing on the Nasdaq of the shares of our common stock to be issued in the first merger; (v) with respect to each party, (a) the accuracy of the other party’s representations and warranties, subject to specified materiality
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qualifications, (b) compliance by the other party with its covenants in the Merger Agreement in all material respects, and (c) the absence of a “Material Adverse Effect” (as defined in the Merger Agreement) with respect to the other party since the date of the Merger Agreement that is continuing; and (vi) in the case of Endeavor, the receipt of an opinion of tax counsel that the Endeavor Acquisition will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended.

No assurance can be given that the required stockholder approval and regulatory clearance will be obtained or that the other required conditions to closing will be satisfied, and, if all required approvals and regulatory clearance are obtained and the required conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such approvals and clearance, including whether any required conditions will materially adversely affect the combined company following the acquisition. Any delay in completing the Endeavor Acquisition could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we and Endeavor expect to achieve if the Endeavor Acquisition is successfully completed within its expected time frame. We can provide no assurance that these conditions will not result in the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and the trading price of our common stock.

The termination of the Merger Agreement could negatively impact our business or result in our having to pay a termination fee.

If the Endeavor Acquisition is not completed for any reason, including as a result of a failure to obtain the required approval from our stockholders, our ongoing business may be adversely affected and, without realizing any of the expected benefits of having completed the Endeavor Acquisition, we would be subject to a number of risks, including the following: (i) we may experience negative reactions from the financial markets, including negative impacts on our stock price; (ii) we may experience negative reactions from our commercial and vendor partners and employees; and (iii) we will be required to pay our costs relating to the Endeavor Acquisition, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Endeavor Acquisition is completed.

Additionally, we are required to pay Endeavor a termination fee of $1.4 billion if the Merger Agreement is terminated by (i) Endeavor because our board of directors has made an adverse change to its recommendation that the our stockholders vote in favor of the issuance of our common stock in the Endeavor Acquisition or (ii) if either party terminates the Merger Agreement because our stockholders fail to approve the issuance of our common stock in the Endeavor Acquisition and, immediately prior to the failed vote, Endeavor would have been entitled to terminate the Merger Agreement because our board of directors had made an adverse change to its recommendation in favor of the issuance of our common stock in the Endeavor Acquisition. If the Merger Agreement is terminated under certain specified circumstances and, within 12 months following such termination, we consummate or enter into an alternative acquisition transaction, we are required to pay the termination fee to Endeavor. Additionally, if the Merger Agreement is terminated because our stockholders fail to approve the issuance of our stock in the Endeavor Acquisition and the termination fee is not payable in connection with such termination, we are required to reimburse Endeavor for its transaction related expenses, subject to a cap of $260 million. The payment of this reimbursement will reduce any termination fee that is subsequently payable by us.

Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business, which could have an adverse effect on our business and financial results.

Whether or not the Endeavor Acquisition is completed, the announcement and pendency of the Endeavor Acquisition could cause disruptions in our business. Specifically: (i) our and Endeavor’s current and prospective employees will experience uncertainty about their future roles with the combined company, which might adversely affect the two companies’ abilities to retain key managers and other employees; (ii) uncertainty regarding the completion of the Endeavor Acquisition may cause our and Endeavor’s commercial and vendor partners or others that deal with us or Endeavor to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Endeavor, which could negatively affect our respective revenues, earnings and cash flows; (iii) the Merger Agreement restricts us and our subsidiaries from taking specified actions during the pendency of the Merger without Endeavor’s consent, which may prevent us from making appropriate changes to our business or organizational structure or prevent us from pursuing attractive business opportunities or strategic transactions that may arise prior to the completion of the Endeavor Acquisition; and (iv) the attention of our and Endeavor’s management may be directed toward the completion of the Endeavor Acquisition as well as integration planning, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to our business.

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We have and will continue to divert significant management resources in an effort to complete the Endeavor Acquisition and are subject to restrictions contained in the Merger Agreement on the conduct of our business. If the Endeavor Acquisition is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit.

Combining our business with Endeavor’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Endeavor Acquisition, which may adversely affect the combined company’s business results and negatively affect the value of the combined company’s common stock.

The success of the Endeavor Acquisition will depend on, among other things, the ability of the two companies to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. The combined company may encounter difficulties in integrating our and Endeavor’s businesses and realizing the anticipated benefits of the Endeavor Acquisition. The combined company must achieve the anticipated improvement in free cash flow generation and returns and achieve the planned cost savings without adversely affecting current revenues or compromising the disciplined investment philosophy for future growth. If the combined company is not able to successfully achieve these objectives, the anticipated benefits of the Endeavor Acquisition may not be realized fully, or at all, or may take longer to realize than expected.

The Endeavor Acquisition involves the combination of two companies which currently operate, and until the completion of the Endeavor Acquisition will continue to operate, as independent companies. There can be no assurances that our respective businesses can be integrated successfully. It is possible that the integration process could result in the loss of key employees from both companies; the loss of commercial and vendor partners; the disruption of our, Endeavor’s or both companies’ ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Endeavor Acquisition, management attention and resources will be required to plan for such integration. An inability to realize the full extent of the anticipated benefits of the Endeavor Acquisition and the other transactions contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of the common stock of the combined company. In addition, the actual integration may result in additional and unforeseen expenses, and the anticipated benefits of the integration plan may not be realized. There are a large number of processes, policies, procedures, operations and technologies and systems that must be integrated in connection with the Endeavor Acquisition and the integration of Endeavor’s business. Although we expect that the elimination of duplicative costs, strategic benefits, and additional income, as well as the realization of other efficiencies related to the integration of the business, may offset incremental transaction and Endeavor Acquisition-related costs over time, any net benefit may not be achieved in the near term or at all. If we and Endeavor are not able to adequately address integration challenges, we may be unable to successfully integrate operations or realize the anticipated benefits of the integration of the two companies.

We also expect to incur significant additional indebtedness in connection with the Endeavor Acquisition, which indebtedness may limit our operating or financial flexibility relative to our current position and make it difficult to satisfy our obligations with respect to our other indebtedness.

We will incur debt to finance all or a portion of the cash consideration for the Endeavor Acquisition and to repay certain existing indebtedness of Endeavor. Our increased level of debt in connection with this debt financing could have negative consequences on us and the combined company, including, among other things, (i) requiring us, and the combined company, to dedicate a larger portion of cash flow from operations to servicing and repayment of the debt, (ii) reducing funds available for strategic initiatives and opportunities, working capital and other general corporate needs, (iii) limiting our, and the combined company’s, ability to incur additional indebtedness, which could restrict its flexibility to react to changes in its business, its industry and economic condition and (iv) placing us, and the combined company, at a competitive disadvantage compared to our competitors that have less debt. See also the risks discussed above under “—Risks Related to Our Indebtedness.”

The market value of our common stock could decline if large amounts of our common stock are sold following the Endeavor Acquisition.

If the Endeavor Acquisition is consummated, we will issue 117.27 million shares of our common stock to Endeavor’s equityholders, and as a result, the Endeavor Stockholders are expected to hold, at closing, approximately 39.5% of our outstanding common stock. At closing, we will enter into the Stockholders Agreement with the Endeavor Stockholders that will, among other things, provide the Endeavor Stockholders with certain shelf, demand and piggyback registration
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rights. While the Endeavor Stockholders will be subject to a lock-up with respect to 90% of the shares of our common stock issued in the Endeavor Acquisition, the lock-up will apply to 66.6% and 33.3% of the shares issued in the Endeavor Acquisition following the six and twelve month anniversaries, respectively, of the closing and will terminate following the eighteen month anniversary of the closing. Endeavor Stockholders may decide not to hold shares of our common stock that they will receive in the Endeavor Acquisition, and Endeavor Stockholders may decide to reduce their investment in us following the Endeavor Acquisition. Such sales of our common stock or the perception that these sales may occur, could have the effect of depressing the market price for our common stock.

Following the closing of the Endeavor Acquisition, the Endeavor Stockholders will have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.

As a result of the Endeavor Acquisition, Endeavor’s Stockholders are expected to hold, at closing, approximately 39.5% of our outstanding common stock. The Stockholders Agreement will provide the Endeavor Stockholders with the right to propose for nomination four directors for election to our board of directors if they beneficially own at least 25% of the outstanding shares of our common stock, two directors if they beneficially own at least 20% but less than 25% of the outstanding shares of our common stock, and one director if they beneficially own at least 10% but less than 20% of the outstanding shares of our common stock, in each case subject to certain qualification requirements for such directors. We will not be permitted to take certain actions without the consent of the holders of a majority of the shares of our common stock held by the Endeavor Stockholders. The Endeavor Stockholders level of ownership and influence may make some transactions (such as those involving mergers, material share issuances or changes in control) more difficult or impossible without the support of the Endeavor Stockholders, which in turn could adversely affect the market price of our shares of common stock or prevent our shareholders from realizing a premium over the market price for their shares of our common stock. The interests of the Endeavor Stockholders may conflict with the interests of other stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS


None.


ITEM 1C. CYBERSECURITY

Cybersecurity Risk Management Strategy

We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. We have engaged third-party consultants to conduct penetration testing and risk assessments. Our cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.

Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.

Our cybersecurity risk management program includes:

•risk assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and our broader enterprise IT environment;
•a security team principally responsible for managing (i) our cybersecurity risk assessment processes, (ii) our security controls, and (iii) our response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of our security controls;
•security tools deployed in the IT environment for protection against and monitoring for suspicious activity;
•cybersecurity awareness training of our employees, including incident response personnel and senior management;
•cybersecurity tabletop exercises for members of our cybersecurity incident response team and legal department;
•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and
•a third-party risk management process for service providers, suppliers, and vendors.

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Cybersecurity Governance

Our cybersecurity governance program is led by the Vice President and Chief Information Officer, with support from the internal information technology department. The Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. The Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), CompTIASecurity+, and Department of Defense (DoD)-Cybersecurity General, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents in accordance with our Computer Security Incident Response Plan. Progress and developments in our cybersecurity governance program are communicated to members of the executive team. The audit committee of the board of directors receives quarterly updates on the status of our cybersecurity governance program, including as related to new or developing initiatives and any security incidents that may occur. Board members receive presentations on cybersecurity topics from the Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Further, our code of business conduct and ethics expects all employees to safeguard our electronic communications systems and related technologies from theft, fraud, unauthorized access, alteration or other damage and requires them to report any cyberattacks or incidents, improper access or theft to our Chief Legal and Administrative Officer and the Vice President and Chief Information Officer. Our cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party vendors and suppliers.

Risks from cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A. Risk Factors of this report for additional information regarding cybersecurity risks we face and their potential impact on our business strategy, results of operations and financial condition.

ITEM 3. LEGAL PROCEEDINGS


DueWe are a party to various routine legal proceedings, disputes and claims arising in the natureordinary course of our business, we are,including those that arise from timeinterpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to time, involved in routine litigation or subjectoil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management,any resulting impact on us, cannot be predicted with certainty, we believe that none of the pending litigation, disputes or claims against us,these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.operations or cash flows. For additional information regarding environmental matters, see Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.


ITEM 4. MINE SAFETY DISCLOSURES


Not applicable.






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PART II


ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES


Price RangeListing and Holders of Common StockRecord
Our common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”.

The following table sets forth the range of high and low sales prices of our common stock for the periods presented:
 High Low
2017   
1st Quarter$114.00
 $96.05
2nd Quarter$108.17
 $83.22
3rd Quarter$98.36
 $82.77
4th Quarter$127.45
 $95.69
2016   
1st Quarter$79.87
 $55.48
2nd Quarter$96.01
 $73.12
3rd Quarter$99.69
 $83.90
4th Quarter$113.23
 $88.74

Holders of Record
There were nine5,207 holders of record of our common stock on February 9, 2018.16, 2024.


Dividend Policy 
We have not paid any cash
Future base and variable dividends since our inception. Covenants contained in our revolving credit facility restrictare at the payment of cash dividends on our common stock. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.”

On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per sharediscretion of our common stock payable quarterly beginning withboard of directors, and the board of directors may change the dividend amount from time to time based on the Company's outlook for commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors. Beginning in the first quarter of 2018. The decision to pay this first dividend or any future dividends, however, is solely within the discretion of, and subject to approval by,2024, our board of directors.directors has approved a reduction in our return of capital commitment to our shareholders to at least 50% from 75% of our quarterly free cash flow through repurchases under our share repurchase program, base dividends and variable dividends. Our board of directors intends to continue the payment of dividends to the holders of the Company’s common stock in the future; however, the Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, whether base or variable, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.


Recent Sales of Unregistered Securities

None.


Issuer Repurchases of Equity Securities
None.


Our common stock repurchase activity for the three months ended December 31, 2023 was as follows:

Period
Total Number of Shares Purchased(1)
Average Price Paid Per Share(2)(4)
Total Number of Shares Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(3)(4)
($ In millions, except per share amounts, shares in thousands)
October 1, 2023 - October 31, 2023226$147.27 218$1,731 
November 1, 2023 - November 30, 202399$149.88 99$1,716 
December 1, 2023 - December 31, 2023556$148.31 556$1,634 
Total881$148.22 873
(1)Includes 8,495 shares of common stock repurchased from executives in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2)The average price paid per share includes any commissions paid to repurchase stock.
(3)On July 28, 2022, our board of directors approved an increase in our common stock repurchase program from $2.0 billion to $4.0 billion, excluding excise tax. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
(4)The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.
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Stock Performance Graph

The following performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500 Index, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP Index. The graph assumes an investment of $100 on December 31, 2018, and that all dividends were reinvested.

1649267444351

As of December 31,
Calculated Values201820192020202120222023
Diamondback Energy, Inc.$100.00$100.91$54.49$123.93$167.93$200.88
S&P 500$100.00$131.47$155.65$200.29$163.98$207.04
XOP$100.00$90.56$57.67$96.18$139.78$144.74

ITEM 6. SELECTED FINANCIAL DATA[RESERVED.]

This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report on Form 10-K.

Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2017, 2016 and 2015 and the balance sheet data as of December 31, 2017 and 2016 are derived from our audited consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2014 and 2013 and the balance sheet data as of December 31, 2015, 2014 and 2013 are derived from our audited financial statements not included in this Annual Report on Form 10-K.
47
 Year Ended December 31,
(In thousands, except per share amounts)2017 2016 2015 2014 2013
Statements of Operations Data:         
Total revenues$1,205,111
 $527,107
 $446,733
 $495,718
 $208,002
Total costs and expenses600,091
 595,724
 1,187,002
 283,048
 112,808
Income (loss) from operations605,020
 (68,617) (740,269) 212,670
 95,194
Other income (expense)(107,831) (96,099) (8,831) 92,286
 (8,853)
Income (loss) before income taxes497,189
 (164,716) (749,100) 304,956
 86,341
Provision for (benefit from) income taxes(19,568) 192
 (201,310) 108,985
 31,754
Net income (loss)516,757
 (164,908) (547,790) 195,971
 54,587
Less: Net income attributable to non-controlling interest34,496
 126
 2,838
 2,216
 —
Net income (loss) attributable to Diamondback Energy, Inc.$482,261
 $(165,034) $(550,628) $193,755
 $54,587
Earnings per common share         
Basic$4.95
 $(2.20) $(8.74) $3.67
 $1.30
Diluted$4.94
 $(2.20) $(8.74) $3.64
 $1.29
Weighted average common shares outstanding         
Basic97,458
 75,077
 63,019
 52,826
 42,015
Diluted97,688
 75,077
 63,019
 53,297
 42,255
 As of December 31,
(In thousands)2017 2016 2015 2014 2013
Balance Sheet Data:         
Cash and cash equivalents$112,446
 $1,666,574
 $20,115
 $30,183
 $15,555
Net property and equipment7,343,617
 3,390,857
 2,597,625
 2,791,807
 1,446,337
Total assets7,770,985
 5,349,680
 2,750,719
 3,095,481
 1,521,614
Current liabilities577,428
 209,342
 141,421
 266,729
 121,320
Long-term debt1,477,347
 1,105,912
 487,807
 673,500
 460,000
Total stockholders’/ members’ equity(1)
5,254,860
 3,697,462
 1,875,972
 1,751,011
 845,541
Total equity5,581,737
 4,018,292
 2,108,973
 1,985,213
 —
 Year Ended December 31,
(In thousands)2017 2016 2015 2014 2013
Other Financial Data:         
Net cash provided by operating activities$888,625
 $332,080
 $416,501
 $356,389
 $155,777
Net cash used in investing activities(3,132,282) (1,310,242) (895,050) (1,481,997) (940,140)
Net cash provided by financing activities689,529
 2,624,621
 468,481
 1,140,236
 773,560


 Year Ended December 31,
(In thousands)2017 2016 2015 2014 2013
Consolidated Adjusted EBITDA(2)
$928,039
 $387,535
 $449,245
 $398,334
 $157,604
(1)For the years ended December 31, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $326.9 million, $320.8 million, $233.0 million and $234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. There was no equity related to non-controlling interest for the year ended December 31, 2013.
(2)Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and a reconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below.

Non-GAAP financial measure and reconciliation

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

The following presents a reconciliation of the non-GAAP financial measure of Consolidated Adjusted EBITDA to the GAAP financial measure of net income (loss).
 Year Ended December 31,
(In thousands)2017 2016 2015 2014 2013
Net income (loss)$516,757
 $(164,908) $(547,790) $195,971
 $54,587
Non-cash (gain) loss on derivative instruments, net84,240
 26,522
 112,918
 (117,109) (5,346)
Interest expense, net40,554
 40,684
 41,510
 34,515
 8,059
Depreciation, depletion and amortization326,759
 178,015
 217,697
 170,005
 66,597
Impairment of oil and natural gas properties—
 245,536
 814,798
 —
 —
Non-cash equity-based compensation expense34,178
 33,532
 24,572
 14,253
 2,724
Capitalized equity-based compensation expense(8,641) (7,079) (6,043) (4,437) (972)
Asset retirement obligation accretion expense1,391
 1,064
 833
 467
 201
Loss on extinguishment of debt—
 33,134
 —
 —
 —
Income tax (benefit) provision(19,568) 192
 (201,310) 108,985
 31,754
Non-controlling interest in net (income) loss(47,631) 843
 (7,940) (4,316) —
Consolidated Adjusted EBITDA$928,039
 $387,535
 $449,245
 $398,334
 $157,604


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10–K.report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See factors discussed further in Item 1A. “Risk Factors”Risk Factors and “CautionaryCautionary Statement Regarding Forward-Looking Statements.”Statements of this report.


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 primarily in the Permian Basin in West Texas. Our activities are primarily directed atAs of December 31, 2023, we have one reportable segment, the horizontal developmentupstream segment. See Note 1—Description of the WolfcampBusiness and Spraberry formationsBasis of Presentation and Note 17—Segment Information in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

2023 Financial and Operating Highlights

•We recorded net income of $3.1 billion.
•Increased our annual base dividend to $3.60 per share of common stock, paid dividends to stockholders of $1.4 billion during 2023 and declared a combined base and variable dividend payable in the first quarter of 2024 of $3.08 per share of common stock.
•Repurchased $838 million of our common stock, leaving approximately $1.6 billion available for future purchases under our common stock repurchase program at December 31, 2023.
•Our cash operating costs were $10.90 per BOE, including lease operating expenses of $5.34 per BOE, cash general and administrative expenses of $0.59 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.97 per BOE.
•Redeemed or repurchased an aggregate of $140 million in principal amount of our 5.250% Senior Notes due 2023, 3.250% Senior Notes due 2026 and 3.500% Senior Notes due 2029.
•Our average production was 447,707 MBOE/d.
•Drilled 350 gross horizontal wells (including 315 in the Midland Basin and 35 in the WolfcampDelaware Basin).
•Turned 310 gross operated horizontal wells (including 263 in the Midland Basin and Bone Spring formations47 in the Delaware Basin) to production.
•As of December 31, 2023, we had approximately 493,769 net acres, which primarily consisted of 349,707 net acres in the Midland Basin and 143,742 net acres in the Delaware Basin. As of December 31, 2023, we had an estimated 7,905 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. In addition, our publicly traded subsidiary, Viper, owns mineral interests underlying approximately 1,197,638 gross acres and 34,217 net royalty acres in the Permian Basin. We intend to continue to develop our reservesoperate approximately 49% of these net royalty acres.
•Incurred capital expenditures, excluding acquisitions, of $2.7 billion.

2023 Transactions and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production.Recent Developments


The following table sets forth our production data for the periods indicated:Acquisitions
 Year Ended December 31,
 2017 2016 2015
Oil (MBbls)74% 73% 75%
Natural gas (MMcf)12% 11% 11%
Natural gas liquids (MBbls)14% 16% 14%
 100% 100% 100%


On December 31, 2017, our acreage positionNovember 1, 2023, Viper closed on the GRP Acquisition, which included 4,600 net royalty acres in the Permian Basin, wasplus an additional 2,700 net royalty acres in other major basins in exchange for approximately 246,0129.02 million Viper common units and $760 million in cash, including customary closing adjustments.

On September 1, 2023, we contributed the Deep Blue Water Assets with a net carrying value of $692 million in exchange for $516 million in cash, a 30% equity ownership and voting interest in the newly formed Deep Blue joint venture and certain contingent consideration.

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On January 31, 2023, we closed on the Lario Acquisition, which included approximately 25,000 gross (206,660 net) acres, which consisted of approximately 117,586 gross (101,941(16,000 net) acres in the Northern Midland Basin and approximately 128,426 gross (104,719 net) acres in the Southern Delaware Basin.

2017 Transactions and Recent Developments

Our Delaware Basin Acquisition

On February 28, 2017, we completed an acquisition ofcertain related oil and natural gas properties, midstream assets and other related assets in the Delaware Basinexchange for an aggregate purchase price consisting of $1.74 billion in cash and 7.694.33 million shares of our common stock and $814 million, including certain customary post-closing adjustments.

Divestitures

On July 28, 2023, we divested our 43% limited liability company interest in OMOG for $225 million in cash received at closing and recorded a gain on the sale of whichequity method investments of approximately 1.15$35 million in the third quarter of 2023 that was included in the caption “Other income (expense), net” on the consolidated statement of operations.

On April 28, 2023, we divested non-core assets with an unrelated third-party buyer consisting of approximately 19,000 net acres in Glasscock County for total consideration of $269 million, including customary post-closing adjustments.

On March 31, 2023, we divested non-core assets consisting of approximately 4,900 net acres in Ward and Winkler counties to unrelated third-party buyers for $72 million in net cash proceeds, including customary post-closing adjustments.

On January 9, 2023, we divested our 10% non-operating equity investment in Gray Oak for $172 million in cash proceeds and recorded a gain on the sale of equity method investments of approximately $53 million in the first quarter of 2023 that was included in “Other income (expense), net” on the consolidated statement of operations.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our acquisitions and divestitures.

Recent Developments

On February 11, 2024, we entered into the Merger Agreement to acquire Endeavor for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 117.27 million shares were placedof our common stock. The Endeavor Acquisition is expected to close in an indemnity escrow. This transaction included the acquisitionfourth quarter of (i)2024, subject to the satisfaction or waiver of customary closing conditions, including the approval of the issuance of our common stock in the Endeavor Acquisition by our stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, the Endeavor Stockholders are expected to hold, at closing, approximately 100,306 gross (80,339 net) acres39.5% of our outstanding common stock.

See Note 16—Subsequent Events in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition.

Commodity Prices and Inflation

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. We used the net proceeds from our December 2016 equity offering, net proceeds from our December 2016 debt offering, cash on handfuture, extreme weather conditions and other financing sourcessubstantially variable factors, influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2023, 2022 and 2021 the NYMEX WTI prices averaged $77.60, $94.33 and $68.11 per Bbl, respectively, and the NYMEX Henry Hub prices averaged $2.66, $6.54 and $3.71 per MMBtu, respectively. The war in Ukraine and the Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2023. Although the impact of inflation on our business has been insignificant in prior periods, inflation in the U.S. has been rising at its fastest rate in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in the energy industry and other sectors, which is contributing to labor and materials shortages across the supply-chain. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels.

Outlook

During 2023, we had total capital expenditures of $2.7 billion, which was consistent with our guidance presented in November 2023. In 2024, we expect to maintain flat production throughout the year with less capital and activity than 2023, thereby promoting our commitment to capital efficiency. Beginning in the first quarter of 2024, our board of directors approved a reduction to our return of capital commitment to our shareholders to at least 50% from 75% of our quarterly free cash flow (as defined in “—Capital Requirements”). Because we will add debt to fund the cash portion of the purchase price for this acquisition.Endeavor Acquisition, we are going to allocate more free cash flow to pay down our debt, with a near-term goal to get pro forma net debt below $10 billion through free cash flow generation and potential non-core asset sales. Our long-term priority is to

New Senior Notes

On January 29, 2018, we issued $300.0 million aggregate principal amount of new 2025 notes as additional notes under our existing indenture, dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under which we previously issued $500.0 million aggregate principal amount of our existing 5.375% Senior Notes due 2025. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.

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Viper Equity Offerings

In January 2017, Viper completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuantreturn cash to an optionstockholders, and we believe using free cash flow to purchase additional common units granted topay down newly-added debt is in the underwriters. Viper received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, Viper completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directorsbest long-term interest of our Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, we had an approximate 64% limited partner interest in Viper. Viper received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $152.8 million to repay all of the then-outstanding borrowings under Viper’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.stockholders.
Operational Update

We are operating ten rigs now and currently intend to operate between ten and twelve drilling rigs in 2018 across our asset base in the Midland and Delaware Basins. We plan to operate six to seven of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, with four to five rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.


In the Midland Basin, we continuecontinued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations. We are currently operating six rigs on the acreage and expect to average approximately six to eight operated rigs in 2018.


In the Delaware Basin, we have now drilledcontinued to target the Wolfcamp and completed multiple wellsBone Spring formations across our primary development areas located in Pecos, Reeves and Ward counties targetingcounties. Collectively, the Wolfcamp A, whichDelaware Basin accounted for approximately 15% of our total development in 2023, and we believe has been de-risked acrossexpect a significantsimilar portion of our total development to be focused in these areas in 2024.

As of December 31, 2023, we were operating 15 drilling rigs and four completion crews and currently intend to operate between 12 and 15 drilling rigs and between three and four completion crews in 2024 on average across our current acreage position and remains our primary development target. Additionally, we have successfully completed additional wells targeting such zones as the Wolfcamp B and 2nd Bone Spring, and expect to test these zones further in 2018. We are currently operating four rigs in the Midland and Delaware Basin and plan to average approximately four to five rigs in 2018.Basins.

We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as our service providers seek to increase pricing following continued strength in the oil market. To combat rising service costs, we have looked to lock in pricing for dedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2018 drilling and completion budget accounts for rising capital costs that we believe will cover potential increases in our service costs during the year.

2018 Capital Budget


We have currently budgeted a 20182024 total capital spend of $1.3$2.30 billion to $1.5$2.55 billion, consistingwhich at the midpoint is a reduction of $1.175 billion10% year over year due to $1.325 billion for horizontal drillinga combination of lower well costs and completions including non-operatedlower activity and $125.0 million to $175.0 million for infrastructure and other expenditures, but excluding the cost of any leasehold and mineral interest acquisitions.expected in 2024. We expect to drill approximately 275 wells and complete 170turn approximately 310 wells to 190production, with almost 30% of those wells expected to be turned to production in the first quarter of 2024. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to maintain flat oil production, pay down indebtedness and return cash to our stockholders.

Environmental Responsibility Initiatives and Highlights

In September 2022, we announced our medium-term goal to reduce Scope 1 and Scope 2 greenhouse gas (“GHG”) intensity by at least 50% from our 2020 level by 2030. In May 2022, we announced our short-term goal to implement continuous emission monitoring systems (“CEMS”) on our facilities to cover at least 90% of operated oil production by the end of 2023. As of December 31, 2023, we had installed CEMS that cover approximately 96% of our operated oil production.

In September 2021, we announced our near-term goal to end routine flaring (as defined by the World Bank) by 2025 and a near-term target to source over 65% of our water used for drilling and completion operations from recycled sources by 2025. For the full year ended 2023, we flared approximately 3.4% of our gross horizontal wellsnatural gas production and sourced approximately 73% of our water used for drilling and completion operations from recycled sources.

In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in 2018.each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we have also implemented our “Net Zero Now” initiative under which, effective January 1, 2021, we strive to produce every hydrocarbon molecule with zero net Scope 1 emissions. To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we have purchased carbon credits to offset the remaining emissions. ESG metrics represent 25% of our annual short-term incentive compensation plan to motivate our executives and our employees to advance our environmental responsibility goals.


Operating Results Overview

The following table summarizes our average daily production for the periods presented:
 Year Ended December 31,
 2017 2016 2015
Oil (Bbls)/d58,678 31,590 24,880
Natural Gas (Mcf)/d56,602 29,313 21,729
Natural Gas Liquids (Bbls)/d11,112 6,556 4,596
Total average production per day79,224 43,031 33,098

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2024 Guidance

Our average daily production for the year ended December 31, 2017 as compared to the year ended December 31, 2016 increased by 36,193 BOE/d, or 84%.

During the year ended December 31, 2017, we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin.

Reserves and pricing

Ryder Scott prepared estimates of our proved reserves at December 31, 2017, 2016 and 2015 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
 2017 2016 2015
Estimated Net Proved Reserves:     
Oil (MBbls)233,181
 139,174
 105,979
Natural gas (MMcf)285,369
 174,896
 149,503
Natural gas liquids (MBbls)54,610
 37,134
 26,004
Total (MBOE)335,352
 205,458
 156,899
 Unweighted Arithmetic Average
 First-Day-of-the-Month Prices
 2017 2016 2015
Oil (per Bbl)$48.03
 $39.94
 $45.07
Natural gas (per Mcf)$2.06
 $1.36
 $1.83
Natural gas liquids (per Bbl)$20.79
 $12.91
 $12.56

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.


The following table presents the sourcesour current estimates of our revenuescertain financial and operating results for the years presented:full year of 2024, as well as production and cash tax guidance for the first quarter of 2024:

 Year Ended December 31,
 2017 2016 2015
Revenues     
Oil sales88% 89% 91%
Natural gas sales4% 4% 4%
Natural gas liquid sales8% 7% 5%
 100% 100% 100%
2024 Guidance
Net production - MBOE/d458 - 466
Oil production - MBO/d270 - 275
Q1 2024 oil production - MBO/d (total - MBOE/d)270 - 274 (458 - 464)
(Unit costs $/BOE):
Lease operating expenses, including workovers$6.00 - $6.50
General and administrative expenses - cash$0.55 - $0.65
Non-cash stock-based compensation$0.40 - $0.50
Depreciation, depletion, amortization and accretion$10.50 - $11.50
Interest expense (net of interest income)$1.05 - $1.25
Gathering, processing and transportation$1.80 - $2.00
Production and ad valorem taxes (% of revenue)~7%
Corporate tax rate (% of pre-tax income)23%
Cash tax rate (% of pre-tax income)15% - 18%
Q1 2024 cash taxes (in millions)$150 - $190

Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2017, WTI posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.


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Principal components of our cost structure

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

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

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

Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.

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

Other income (expense)

Interest income (expense). We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This amount reflects interest paid to our lender plus the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees net of interest received on our cash and cash equivalents.

Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivative instruments.

Deferred tax assets (liabilities). We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.


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Results of Operations


Comparison of the Years Ended December 31, 2023 and 2022

For a discussion of the results of operations for the year ended December 31, 2022 as compared to the year ended December 31, 2021, please refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2022 (filed with the SEC on February 23, 2023), which is incorporated in this report by reference from such prior report on Form 10-K.

The following table sets forth selected historical operating data for the periods indicated.indicated:
Year Ended December 31,
20232022
Revenues (in millions):
Oil sales$7,279 $7,660 
Natural gas sales262 858 
Natural gas liquid sales687 1,048 
Total oil, natural gas and natural gas liquid revenues$8,228 $9,566 
Production Data:
Oil (MBbls)96,176 81,616 
Natural gas (MMcf)198,117 176,376 
Natural gas liquids (MBbls)34,217 29,880 
Combined volumes (MBOE)(1)
163,413 140,892 
Daily oil volumes (BO/d)263,496 223,605 
Daily combined volumes (BOE/d)447,707 386,005 
Average Prices:
Oil ($ per Bbl)$75.68 $93.85 
Natural gas ($ per Mcf)$1.32 $4.86 
Natural gas liquids ($ per Bbl)$20.08 $35.07 
Combined ($ per BOE)$50.35 $67.90 
Oil, hedged ($ per Bbl)(2)
$74.72 $86.76 
Natural gas, hedged ($ per Mcf)(2)
$1.48 $4.12 
Natural gas liquids, hedged ($ per Bbl)(2)
$20.08 $35.07 
Average price, hedged ($ per BOE)(2)
$49.98 $62.85 
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following table provides information on the mix of our production for the years ended December 31, 2023 and 2022:
Year Ended December 31,
20232022
Oil (MBbls)59 %58 %
Natural gas (MMcf)20 %21 %
Natural gas liquids (MBbls)21 %21 %
100 %100 %
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 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Revenues     
Oil, natural gas liquids and natural gas$1,186,275
 $527,107
 $446,733
Lease bonus11,764
 —
 —
Midstream services7,072
 —
 —
Total revenues1,205,111
 527,107
 446,733
Operating expenses     
Lease operating expenses126,524
 82,428
 82,625
Production and ad valorem taxes73,505
 34,456
 32,990
Gathering and transportation12,834
 11,606
 6,091
Midstream services10,409
 —
 —
Depreciation, depletion and amortization326,759
 178,015
 217,697
Impairment of oil and natural gas properties—
 245,536
 814,798
General and administrative expenses48,669
 42,619
 31,968
Asset retirement obligation accretion1,391
 1,064
 833
Total expenses600,091
 595,724
 1,187,002
Income (loss) from operations605,020
 (68,617) (740,269)
Interest expense, net(40,554) (40,684) (41,510)
Other income, net10,235
 3,064
 728
Gain (loss) on derivative instruments, net(77,512) (25,345) 31,951
Loss on extinguishment of debt—
 (33,134) —
Total other expense, net(107,831) (96,099) (8,831)
Income (loss) before income taxes497,189
 (164,716) (749,100)
Provision for (benefit from) income taxes(19,568) 192
 (201,310)
Net income (loss)516,757
 (164,908) (547,790)
Net income attributable to non-controlling interest34,496
 126
 2,838
Net income (loss) attributable to Diamondback Energy, Inc.$482,261
 $(165,034) $(550,628)


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See Items 1 and 2. Business and Properties—Oil and Natural Gas Data—Oil and Natural Gas Production and Price History of this report for further discussion of production by basin.

 Year Ended December 31,
 2017 2016 2015
Production Data:     
Oil (MBbls)21,418
 11,562
 9,081
Natural gas (MMcf)20,660
 10,728
 7,931
Natural gas liquids (MBbls)4,056
 2,399
 1,678
Combined volumes (MBOE)28,917
 15,749
 12,081
Daily combined volumes (BOE/d)79,224
 43,031
 33,098
      
Average Prices:     
Oil (per Bbl)$48.75
 $40.70
 $44.68
Natural gas (per Mcf)2.53
 2.10
 2.47
Natural gas liquids (per Bbl)22.20
 14.20
 12.77
Combined (per BOE)41.02
 33.47
 36.98
Oil, hedged ($ per Bbl)(1)
48.94
 40.80
 60.63
Natural gas, hedged ($ per MMbtu)(1)
2.65
 2.06
 2.47
Average price, hedged ($ per BOE)(1)
41.26
 33.54
 48.97
      
Average Costs per BOE:     
Lease operating expense$4.38
 $5.23
 $6.84
Production and ad valorem taxes2.54
 2.19
 2.73
Gathering and transportation expense0.44
 0.74
 0.50
General and administrative - cash component0.80
 1.03
 1.11
Total operating expense - cash$8.16
 $9.19
 $11.18
      
General and administrative - non-cash component$0.88
 $1.68
 $1.54
Depreciation, depletion and amortization11.30
 11.30
 18.02
Interest expense1.40
 2.58
 3.44
Total expenses$13.58
 $15.56
 $23.00
      
Average realized oil price ($/Bbl)$48.75
 $40.70
 $44.68
Average NYMEX ($/Bbl)$50.80
 $43.29
 $48.66
Differential to NYMEX$(2.05) $(2.59) $(3.98)
Average realized oil price to NYMEX96% 94% 92%
      
Average realized natural gas price ($/Mcf)$2.53
 $2.10
 $2.47
Average NYMEX ($/Mcf)$2.99
 $2.52
 $2.62
Differential to NYMEX$(0.46) $(0.42) $(0.15)
Average realized natural gas price to NYMEX85% 83% 94%
      
Average realized natural gas liquids price ($/Bbl)$22.20
 $14.20
 $12.77
Average NYMEX oil price ($/Bbl)$50.80
 $43.29
 $48.66
Average realized natural gas liquids price to NYMEX oil price44% 33% 26%
(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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Comparison of the Years Ended December 31, 2017 and 2016

Oil, Natural Gas Liquids and Natural Gas Liquids Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $659.2 million, or 125%, to $1.2 billion for the year ended December 31, 2017 from $527.1 million for the year ended December 31, 2016. Our revenues are a function of oil, natural gas liquids and natural gas liquids production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 36,193 BOE/d to 79,224 BOE/d during the year ended December 31, 2017 from 43,031 BOE/d during the year ended December 31, 2016. The total increase in revenue of approximately $659.2 million is attributable to higher
Our oil, natural gas liquids and natural gas production volumes and higher average sales pricesliquids revenues decreased by approximately $1.3 billion, or 14%, to $8.2 billion for the year ended December 31, 2017 as compared to the year ended December 31, 2016. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 9,856 MBbls of oil, 1,656 MBbls of natural gas liquids and 9,931 MMcf of natural gas2023 from $9.6 billion for the year ended December 31, 2017 as compared2022, primarily due to the year ended December 31, 2016.

The net dollar effecta reduction of the increases in prices of approximately $213.7 million (calculated as the change in period-to-period$3.0 billion attributable to lower average prices multiplied by current periodreceived for our oil production volumes of oil,and to a lesser extent, our natural gas and natural gas liquids and natural gas)production. The decrease from lower average prices was partially offset by an increase of $1.7 billion attributable to the 16% growth in our combined volumes. Approximately 65% of the growth in combined production volumes is attributable to the FireBird Acquisition and the Lario Acquisition, with the remainder primarily attributable to new wells drilled on previously existing acreage.

Net Sales of Purchased Oil. Beginning in the third quarter of 2023, we entered into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments.

The following table presents the net dollar effectsales of the increase in production of approximately $445.4 million (calculated as the increase in period-to-period volumes forpurchased oil natural gas liquids and natural gas multiplied by the period average prices) are shown below.
 Change in prices 
Production volumes(1)
 Total net dollar effect of change
     (in thousands)
Effect of changes in price:     
Oil$8.05
 21,418
 $172,403
Natural gas liquids$8.00
 4,056
 $32,446
Natural gas$0.43
 20,660
 $8,884
Total revenues due to change in price    $213,733
      
 
Change in production volumes(1)
 Prior period average prices Total net dollar effect of change
     (in thousands)
Effect of changes in production volumes:     
Oil9,856
 $40.70
 $401,080
Natural gas liquids1,656
 $14.20
 $23,521
Natural gas9,931
 $2.10
 $20,834
Total revenues due to change in production volumes    $445,435
Total change in revenues    $659,168
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. Lease bonus revenue was $11.8 millionfrom third parties for the year ended December 31, 2017, $2.8 million of which was attributable to lease bonus payments to extend2023 and 2022:

Year Ended December 31,
(In millions)20232022
Sales of purchased oil$111 $— 
Purchased oil expense111 — 
Net sales of purchased oil$— $— 

Other Revenues. The following table shows the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. We had no lease bonus revenueother insignificant revenues for the year ended December 31, 2016.2023 and 2022:


Midstream Services Revenue. Midstream services revenue was $7.1
Year Ended December 31,
(In millions)20232022
Other operating income$73 $77 

Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2023 and 2022:
Year Ended December 31,
20232022
(In millions, except per BOE amounts)AmountPer BOEAmountPer BOE
Lease operating expenses$872 $5.34 $652 $4.63 

Lease operating expenses increased by $220 million, or $0.71 per BOE for the year ended December 31, 2017. We had no midstream services revenue for2023 as compared to the year ended December 31, 2016. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportationsame period in 2022. The increase primarily consists of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.

Lease Operating Expenses. Lease operating expenses were $126.5(i) $119 million ($4.38 per BOE) for the year ended December 31, 2017, an increase of $44.1 million from $82.4 million ($5.23 per BOE) for the year ended December 31, 2016. The increase in lease operating expense was due to an increase of 234 producing wells compared to 2016. This increase was  offset by higherexpenses incurred on production volumes which resultedfrom the FireBird Acquisition and the Lario Acquisition, (ii) $33 million in additional costs incurred for water services as a decreaseresult of divesting the Deep Blue Water Assets in lease operating expense per BOE.the third quarter of 2023, and (iii) increases in other individually insignificant costs due primarily to inflationary pressures.


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Production and Ad Valorem Taxes. ProductionTax Expense. The following table shows production and ad valorem taxes increased to $73.5 milliontax expense for the yearyears ended December 31, 2017 from $34.5 million for the year ended December 31, 2016. 2023 and 2022:
Year Ended December 31,
20232022
(In millions, except per BOE amounts)AmountPer BOEPercentage of oil, natural gas and natural gas liquids revenueAmountPer BOEPercentage of oil, natural gas and natural gas liquids revenue
Production taxes$380 $2.32 4.6 %$483 $3.43 5.0 %
Ad valorem taxes145 0.89 1.8 128 0.91 1.3 
Total production and ad valorem expense$525 $3.21 6.4 %$611 $4.34 6.3 %

In general, production taxes and ad valorem

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taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxesrevenues and are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2017 as compared to 2016 was primarily due to an increase in our productionProduction taxes as a resultpercentage of increased commodity prices and volumes.

Midstream Services Expense. Midstream services expense was $10.4 millionproduction revenues decreased slightly for the year ended December 31, 2017. We had no midstream services expense2023 compared to the same period in 2022, primarily due to a decrease in natural gas and natural gas liquids sales, which have a higher production tax rate.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the year ended December 31, 2016. Midstream services expense represents costs incurred2023 compared to operatethe same period in 2022 increased by $17 million, which consisted of $20 million in additional ad valorem taxes for properties acquired in the FireBird Acquisition and maintain our oilthe Lario Acquisition, partially offset by a decrease in tax rates for multiple taxing authorities.

Gathering, Processing and natural gasTransportation Expense. The following table shows gathering, processing and transportation systems, natural gas lift, compression infrastructureexpense for the years ended December 31, 2023 and water2022:

Year Ended December 31,
20232022
(In millions, except per BOE amounts)AmountPer BOEAmountPer BOE
Gathering, processing and transportation$287 $1.76 $258 $1.83 

The increase in gathering, processing and transportation facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $148.7 million, or 84%, from $178.0 millionexpenses for the year ended December 31, 20162023 compared to $326.8 million for the year ended December 31, 2017.same period in 2022 is primarily attributable to the growth in production volumes discussed above. The rate per BOE decreased between periods primarily due to the 2022 period including additional fees incurred on minimum volume commitments.


Depreciation, Depletion, Amortization and Accretion.The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:years ended December 31, 2023 and 2022:
Year Ended December 31,
(In millions, except BOE amounts)20232022
Depletion of proved oil and natural gas properties$1,669 $1,250 
Depreciation of other property and equipment56 77 
Other amortization6 3 
Asset retirement obligation accretion15 14 
Depreciation, depletion, amortization and accretion expense$1,746 $1,344 
Oil and natural gas properties depletion rate per BOE$10.21 $8.87 
Depreciation, depletion, amortization and accretion per BOE$10.68 $9.54 
 Year Ended December 31,
 2017 2016
 (in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties$321,870
 $176,369
Depreciation of midstream assets3,451
 252
Depreciation of other property and equipment1,438
 1,394
Depreciation, depletion and amortization expense$326,759
 $178,015
Oil and natural gas properties depreciation, depletion and amortization expense per BOE$11.11
 $11.23
Total depreciation, depletion and amortization expense per BOE$11.30
 $11.30


The increase in depletion of proved oil and natural gas properties of $145.5$419 million for the year ended December 31, 20172023 as compared to the yearsame period in 2022 resulted primarily from (i) $129 million in additional depletion on production from the FireBird Acquisition and the Lario Acquisition, (ii) $71 million from the increase in other production volumes, and (iii) $219 million due to an increase in the depletion rate resulting from the addition of leasehold costs and reserves from the FireBird Acquisition, the Lario Acquisition and the GRP Acquisition.

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General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2016 resulted primarily from higher production levels2023 and an2022:
Year Ended December 31,
20232022
(In millions, except per BOE amounts)AmountPer BOEAmountPer BOE
General and administrative expenses$96 $0.59 $89 $0.63 
Non-cash stock-based compensation54 0.33 55 0.39 
Total general and administrative expenses$150 $0.92 $144 $1.02 

The increase in net book value on new reserves added.

Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2016, we recorded an impairment of oil and gas properties of $245.5 million as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves. We did not record an impairment of oil and natural gas properties during the year ended December 31, 2017.
General and Administrative Expenses. Generalgeneral and administrative expenses increased $6.1 million from $42.6 million for the year ended December 31, 20162023 compared to $48.7the same period in 2022 was primarily due to $6 million in additional professional services and legal costs in the current year and to a lesser extent, additional payroll and other employee driven costs.

Other Operating Costs and Expenses. The following table shows the other operating costs and expenses for the year ended December 31, 2017. 2023 and 2022:

Year Ended December 31,
(In millions)20232022
Merger and integration expenses$11 $14 
Other operating expenses$140 $112 

The increase wasin other operating expenses for the year ended December 31, 2023 compared to the same period in 2022 primarily resulted from additional midstream services expenses incurred for activity on leasehold acreage obtained in the FireBird Acquisition and Lario Acquisition.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2023 and 2022:

Year Ended December 31,
(In millions)20232022
Gain (loss) on derivative instruments, net$(259)$(586)
Net cash received (paid) on settlements(1)
$(110)$(850)
(1)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $138 million.

We recorded losses on our derivative instruments for the years ended December 31, 2023 and 2022 primarily due to anmarket prices being higher than the strike prices on our derivative contracts.

See Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data of this report for further details regarding our derivative instruments and interest rate swaps.

Other Income (Expense). The following table shows other income and expenses for the years ended December 31, 2023 and 2022:

Year Ended December 31,
(In millions)20232022
Interest expense, net$(175)$(159)
Other income (expense), net$68 $(5)
Gain (loss) on extinguishment of debt$(4)$(99)
Income (loss) from equity investments, net$48 $77 

The increase in salaries and benefits expense as a result of an increase in workforce.

Net Interest Expense. Netnet interest expense for the year ended December 31, 2017 was $40.6 million as2023 compared to $40.7the same period in 2022, reflects (i) a net increase of $62 million in interest expense on our senior notes which consisted of $108 million in additional interest costs on senior notes issued during 2023 and 2022, partially offset by a reduction of $46 million from the impact of retirements of various other senior notes in 2023 and 2022, and (ii) an $11 million increase in interest expense on our and
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Viper’s revolving credit facilities due primarily to higher weighted average interest rates and borrowings to fund the cash portion of acquisitions and other corporate expenses. These increases were partially offset by a $47 million increase in capitalized interest costs, which reduce interest expense, and other insignificant reductions in interest income and the amortization of debt issuances costs and discounts.

Other income (expense), net for the year ended December 31, 2016,2023 includes a decrease$53 million gain on the sale of $0.1 million. This decrease was due primarily toour equity method investment in Gray Oak and a $35 million gain on the issuancesale of our equity method investment in October 2016OMOG as discussed further in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of new senior notes due 2024 with a lower interest rate than the senior notes which we redeemed in the fourth quarter of 2016this report, partially offset by various other insignificant expenses.

Gain (loss) on extinguishment of debt reflects the interest ondifference between the additionalcarrying value and reacquisition price for the repurchases and redemptions of various senior notes dueduring the 2023 and 2022 periods.

See Note 8—Debt in 2025 that we issued in December 2016.

Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedgesItem 8. Financial Statements and Supplementary Data of this report for accounting purposes. As a result, we mark our derivative instruments to fair valuefurther details regarding outstanding borrowings, interest expense and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gaingain (loss) on derivative instruments, net.” Forextinguishment of debt.

The decrease in income from our equity investments primarily reflects a reduction of $19 million due to the years ended December 31, 2017sale of Gray Oak in January 2023 and 2016, we hadan $18 million decrease in income from the WTG joint venture in 2023 compared to 2022, primarily due to lower commodity prices in 2023. This was slightly offset by a cash gain on settlement$5 million increase in income from the Wink to Webster Pipeline and a $2 million increase in net income from the Deep Blue equity method investment acquired in September 2023. See Note 7—Equity Method Investments and Related Party Transactions in Item 8. Financial Statements and Supplementary Data of derivative instruments of $6.7 million and $1.2 million, respectively. For the year ended December 31, 2017 and 2016, we had a negative change in the fair value of open derivative instruments of $84.2 million and $26.5 million, respectively.this report for further discussion.


Provision for (Benefit from) Income Taxes. We recorded anThe following table shows the provision for (benefit from) income tax benefit of $19.6 milliontaxes for the yearyears ended December 31, 2017 as compared to an income tax provision of $0.2 million for the year ended December 31, 2016. Our effective tax rate was (3.9)% for the year ended December 31, 2017 as compared to (0.1)% for the year ended December 31, 2016. 2023 and 2022:
Year Ended December 31,
(In millions)20232022
Provision for (benefit from) income taxes$912 $1,174 

The change in our income tax provision for the year ended December 31, 2017 as2023 compared to the year ended December 31, 2016 issame period in 2022 was primarily due to the reductiondecrease in our valuation allowance against deferred tax assets, as well as the favorable impact of the

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reduction in the federal statutory tax rate enacted in December 2017. While we generated positive pre-tax income resulting largely from continuing operationsthe decline in 2017, our 2017 effective tax rate was negative due to the income tax benefit generated by these items.


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Comparison of the Years Ended December 31, 2016revenues from oil, natural gas and 2015

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increasedwas partially offset by approximately $80.4 million, or 18%, to $527.1 millionthe discrete income tax benefit recognized for the year ended December 31, 2016 from $446.7 million for the year ended December 31, 2015. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 9,933 BOE/d to 43,031 BOE/d during the year ended December 31, 2016 from 33,098 BOE/d during the year ended December 31, 2015. The total increase in revenue of approximately $80.4 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes partially offset by lower average sales prices for the year ended December 31, 2016 as compared to the year ended December 31, 2015. The increases in production volumes were due2022 related to a combinationreduction in Viper’s valuation allowance against its deferred tax assets. See Note 11—Income Taxes in Item 8. Financial Statements and Supplementary Data of increased drilling activity and growth through acquisitions. Our production increased by 2,481 MBbls of oil, 722 MBbls of natural gas liquids and 2,797 MMcf of natural gasthis report for the year ended December 31, 2016 as compared to the year ended December 31, 2015.

The net dollar effect of the decreases in prices of approximately $46.6 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $126.9 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.

 Change in prices 
Production volumes(1)
 Total net dollar effect of change
     (in thousands)
Effect of changes in price:     
Oil$(3.98) 11,562
 $(46,031)
Natural gas liquids$1.43
 2,399
 $3,431
Natural gas$(0.37) 10,728
 $(3,970)
Total revenues due to change in price    $(46,570)
      
 
Change in production volumes(1)
 Prior period average prices Total net dollar effect of change
     (in thousands)
Effect of changes in production volumes:     
Oil2,481
 $44.68
 $110,815
Natural gas liquids722
 $12.77
 $9,219
Natural gas2,797
 $2.47
 $6,910
Total revenues due to change in production volumes    $126,944
Total change in revenues    $80,374
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Operating Expenses. Lease operating expenses were $82.4 million ($5.23 per BOE) for the year ended December 31, 2016, a decrease of $0.2 million from $82.6 million ($6.84 per BOE) for the year ended December 31, 2015. The decrease is a result of efficiencies we achieved in our field operations. Upon becoming the operator of wells acquired in our acquisitions, we seek to achieve the efficiencies in those wells that we have established with our existing portfolio of wells.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $34.5 million for the year ended December 31, 2016 from $33.0 million for the year ended December 31, 2015. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2016 as compared to 2015 was primarily due to an increase in our production taxes as a result of increased production partially offset by lower ad valorem taxes.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $39.7 million, or 18%, from $217.7 million for the year ended December 31, 2015 to $178.0 million for the year ended December 31, 2016.


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The following table provides componentsfurther discussion of our depreciation, depletion and amortization expense for the periods presented:
 Year Ended December 31,
 2016 2015
 (in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties$176,369
 $216,056
Depreciation of midstream assets252
 239
Depreciation of other property and equipment1,394
 1,402
Depreciation, depletion and amortization expense$178,015
 $217,697
Oil and natural gas properties depreciation, depletion and amortization expense per BOE$11.23
 $17.84
Total depreciation, depletion and amortization expense per BOE$11.30
 $18.02

The decreases in depletion of proved oil and natural gas properties of $39.7 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015 resulted primarily from the impairment of oil and gas properties recorded in 2016.

Impairment of Oil and Natural Gas Properties. During the years ended December 31, 2016 and 2015, we recorded impairments of oil and gas properties of $245.5 million and $814.8 million, respectively, as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves.
General and Administrative Expenses. General and administrative expenses increased $10.7 million from $32.0 million for the year ended December 31, 2015 to $42.6 million for the year ended December 31, 2016. The increase was due to increases in salaries and benefits expense as a result of an increase in workforce and equity-based compensation.

Net Interest Expense. Net interest expense for the year ended December 31, 2016 was $40.7 million as compared to $41.5 million for the year ended December 31, 2015, a decrease of $0.8 million. This decrease was due primarily to the lower average level of outstanding borrowings under our credit facility during 2016.

Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2016 and 2015, we had a cash gain on settlement of derivative instruments of $1.2 million and $144.9 million, respectively. For the year ended December 31, 2016 and 2015, we had a negative change in the fair value of open derivative instruments of $26.5 million and $112.9 million, respectively.

Provision for (Benefit from) Income Taxes. We recorded an income tax expense of$0.2 million for the year ended December 31, 2016 as compared to an income tax benefit of $201.3 million for the year ended December 31, 2015. Our effective tax rate was (0.1%) for the year ended December 31, 2016 as compared to 26.9% for the year ended December 31, 2015.expense.



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Liquidity and Capital Resources


Our
Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity have beenincluded cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations.sales of non-core assets. Our primary useuses of capital hashave been for the acquisition, development and exploration of oil and natural gas properties and repayment of debt and returning capital to stockholders. At December 31, 2023, we had approximately $2.2 billion of liquidity consisting of $556 million in standalone cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2024 is $2.30 billion to $2.55 billion. As of December 31, 2023, we have no debt maturities until 2026.

Future cash flows are subject to a number of variables, including the level of oil and natural gas production and volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our properties. Prices for our commodities are determined primarily by prevailing market conditions, regional and worldwide economic activity, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict. See Item 1A. Risk Factors of this report above. In order to mitigate this volatility, we enter into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, to economically hedge a portion of our estimated future crude oil and natural gas production as discussed further in Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Riskof this report. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

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Cash Flow

Our cash flows for the years ended December 31, 2023 and 2022 are presented below:
Year Ended December 31,
20232022
(In millions)
Net cash provided by (used in) operating activities$5,920 $6,325 
Net cash provided by (used in) investing activities(3,323)(3,330)
Net cash provided by (used in) financing activities(2,176)(3,503)
Net change in cash$421 $(508)

Operating Activities

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

The decrease in operating cash flows for the year ended December 31, 2023 compared to the same period in 2022 primarily resulted from (i) a decrease of $1.2 billion in total revenue, and (ii) an increase in our cash operating expenses of approximately $306 million. These were partially offset by (i) a reduction of $740 million in net cash paid on settlements of derivative contracts, (ii) a reduction of $366 million in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable, including taxes receivable, and payments made on accounts payable. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

The majority of our net cash used for investing activities during the year ended December 31, 2023 and 2022 was for drilling and completion costs in conjunction with our development program as well as the purchase of oil and gas properties including the Lario Acquisition and GRP Acquisition. These cash outflows were partially offset by proceeds received from the divestitures of various oil and gas properties and other assets, which are discussed further in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:
Year Ended December 31,
20232022
(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties$2,429 $1,685 
Infrastructure additions to oil and natural gas properties153 169 
Additions to midstream assets119 84 
Total$2,701 $1,938 

For further discussion regarding our development program, please see Items 1 and 2. Business and Properties—Oil and Natural Gas Data—Wells Drilled and Completed in 2023 of this report.

Financing Activities

During the year ended December 31, 2023, net cash used in financing activities was primarily attributable to (i) $1.4 billion of dividends paid to stockholders as we continued our return of capital program, (ii) $935 million of repurchases as part of the Diamondback and Viper share repurchase programs, (iii) $134 million paid for the retirement of principal outstanding on certain senior notes, and (iv) $129 million in distributions to non-controlling interest. These cash outflows were partially offset by $394 million in net proceeds from the issuance of the Viper 2031 Notes and an additional $111 million in borrowings under credit facilities, net of repayments.
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Net cash used in financing activities for the year ended December 31, 2022 was primarily attributable to (i) $2.4 billion paid for the retirement of outstanding principal on certain senior notes, as well as $63 million of additional premiums paid in connection with the repurchases, (ii) $1.3 billion of repurchases as part of the share and unit repurchase programs, (iii) $1.6 billion of dividends paid to stockholders, and (iv) $217 million in distributions to non-controlling interest. The cash outflows were partially offset by (i) $2.5 billion in proceeds from our senior notes issued in 2022, and (ii) $347 million of payments under our and our subsidiaries’ credit facilities, net of borrowings.

Capital Resources

Our working capital requirements are supported by our cash and cash equivalents and available borrowings under our revolving credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program and to finance the pending Endeavor Acquisition. Because of the alternatives available to us, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term capital requirements.

As we pursue reservesour business and production growth,financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and Cash Flow

Our cash flows for Continued prolonged volatility in the years ended December 31, 2017, 2016 and 2015 are presented below:
 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Net cash provided by operating activities$888,625
 $332,080
 $416,501
Net cash used in investing activities(3,132,282) (1,310,242) (895,050)
Net cash provided by financing activities$689,529
 $2,624,621
 $468,481
Net change in cash$(1,554,128) $1,646,459
 $(10,068)

Operating Activities

Net cash provided by operating activities was $888.6 million for the year ended December 31, 2017 as compared to $332.1 million for the year ended December 31, 2016. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenuescapital, financial and/or credit markets due to anthe war in Ukraine and Israel-Hamas war, and/or adverse macroeconomic conditions may limit our access to, or increase in average pricesour cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and production growth during the year ended December 31, 2017.

Net cash provided by operating activities was $332.1 million for the year ended December 31, 2016 as compared to $416.5 million for the year ended December 31, 2015. The decrease in operating cash flows is primarily the result of a higher gain on settlement of derivative instruments during the year ended December 31, 2015 as compared to the year ended December 31, 2016.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sources of our revenue” and Item 1A. “Risk Factors” above.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $3.1 billion, $1.3 billion and $895.1 million during the years ended December 31, 2017, 2016 and 2015, respectively.

During the year ended December 31, 2017, we spent (a) $860.7 million on capital expenditures in conjunction with our drilling program, in which we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated wells, (b) $68.1 million on additions to midstream assets, (c) $407.5 million for the acquisition of mineral interests, (d) $1,960.6 million on leasehold acquisitions, (e) $50.3 million for the acquisition of midstream assets and (f) $22.8 million for the purchase of other property and equipment.

During the year ended December 31, 2016, we spent (a) $364.3 million on capital expenditures in conjunction with our drilling program, in which we drilled 73 gross (61 net) horizontal wells and two gross (one net) vertical wells and participated in the drilling of 19 gross (five net) non-operated wells, (b) $611.3 million on leasehold acquisitions, (c) $205.7 million on royalty interest acquisitions, (d) $9.9 million for the purchase of other property and equipment and (e) $121.4 million was placed in escrow as a deposit under the purchase agreement for oil and natural gas assets located in Pecos and Reeves counties in Texas.


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During the year ended December 31, 2015, we spent (a) $419.5 million on capital expenditures in conjunction with our drilling program, in which we drilled 64 gross (54 net) horizontal wells and four gross (three net) vertical wells and participated in the drilling of 15 gross (six net) non-operated wells, (b) $437.5 million on leasehold acquisitions, (c) $43.9 million on royalty interest acquisitions and (d) $1.2 million for the purchase of other property and equipment.

Our investing activities for the years ended December 31, 2017, 2016 and 2015 are summarized in the following table:
 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Drilling, completion and infrastructure$(860,738) $(363,087) $(419,512)
Additions to midstream assets(68,139) (1,188) —
Acquisition of leasehold interests(1,960,591) (611,280) (437,455)
Acquisition of mineral interests(407,450) (205,721) (43,907)
Acquisition of midstream assets(50,279) —
 —
Purchase of other property and equipment(22,779) (9,891) (1,213)
Proceeds from sale of property and equipment65,656
 4,661
 9,739
Funds held in escrow104,087
 (121,391) —
Equity investments(188) (2,345) (2,702)
Net cash used in investing activities$(3,200,421) $(1,310,242) $(895,050)

Financing Activities
Net cash provided by financing activities for the years ended December 31, 2017, 2016 and 2015 was $689.5 million, $2.6 billion and $468.5 million, respectively.

During the year ended December 31, 2017, the amount provided by financing activities was primarily attributable to proceeds from Viper’s January and July 2017 equity offerings of $370.3 million as well as borrowings net of repayments of $370.0 million partially offset by distributions to non-controlling interests of $41.4 million.

During the year ended December 31, 2016, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $2.1 billion from our January, July and December 2016 equity offerings partially offset by repayments of net borrowings of $75.0 million under our credit facility.

During the year ended December 31, 2015, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $650.7 million from our January, May and August 2015 equity offerings of $650.7 million partially offset by repayments of net borrowings of $184.5 million under our credit facility.

2024 Senior Notes

On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the 2024 senior notes. The 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2024 senior notes; provided, however, that the 2024 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the our future unrestricted subsidiaries.

The 2024 senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented. The 2024 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.

We may on any one or more occasions redeem some or all of the 2024 senior notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning

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on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, we may on any one or more occasions redeem all or a portion of the 2024 senior notes at a price equal to 100% of the principal amount of the 2024 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, we may on any one or more occasions redeem the 2024 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 senior notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

2025 Senior Notes

On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture (which, as may be amended or supplemented from time to time, is referred to as the 2025 Indenture) among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On July 27, 2017, we exchanged all of the existing 2025 notes for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes, as additional notes under the 2025 Indenture. The new 2025 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We refer to the new 2025 notes, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.
We may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, we may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, we may on any one or more occasions redeem the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

Under a registration rights agreement executed in connection with the issuance of the new 2025 notes, we and our subsidiary guarantors agreed to file, subject to certain conditions, a registration statement relating to the new 2025 notes with the SEC pursuant to which we will either offer to exchange the new 2025 notes for registered notes with substantially identical terms or, in certain circumstances, register the resale of the new 2025 notes. Additional interest on the new 2025 notes may become payable if we do not comply with our obligations under the registration rights agreement relating to the new 2025 notes.
Second Amended and Restated Credit Facility

Our credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for

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a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we may request up to two additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, we had elected a commitment amount of $1.0 billion and we had borrowings of $397.0 million outstanding under the revolving credit facility. Of this amount, we repaid $308.5 million with the net proceeds from our issuance of the new 2025 notes on January 29, 2018. Immediately following the completion of the new 2025 notes offering and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility.

Diamondback O&G LLC is the borrower under our credit agreement. As of December 31, 2017, the credit agreement is guaranteed by us, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margin depends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.

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

Financial CovenantRequired Ratio
Ratio of total debt to EBITDAXNot greater than 3.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
As of December 31, 2017, we were in compliance with all financial covenants2023, the maximum credit amount available under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary eventswas $1.6 billion, which may be increased to a total maximum commitment amount of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy$2.6 billion, with no outstanding borrowings. Our credit agreement matures on June 2, 2028, and change of control. With certain specified exceptions,may further extend it by one one-year extension pursuant to the terms and provisions of our revolvingset forth in the credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.agreement.


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Viper’s Facility-Wells Fargo BankCredit Agreement


On July 8, 2014,The Viper entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended to date, matures on September 22, 2028 and provides for a revolving credit facility in the maximum credit amount of $2.0 billion, andwith a borrowing base of $1.3 billion as of December 31, 2023, although Viper had an elected commitment amount of $850 million, based on ourViper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As offactors. At December 31, 2017, the borrowing base was set at $400.0 million, and Viper had $93.52023, there were $263 million of outstanding borrowings and $306.5$587 million available for future borrowings under the Viper credit agreement.

Issuance of Viper 2031 Notes

On October 19, 2023, Viper issued $400 million in aggregate principal amount of its revolving credit facility.7.375% Senior Notes maturing on November 1, 2031. Through maturity, Viper expects to incur approximately $236 million in aggregate interest costs (approximately $30 million annually) for the Viper 2031 Notes.


TheFor additional discussion of our outstanding borrowings underdebt as of December 31, 2023, see Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report.

Debt Ratings

We receive debt ratings from the credit agreement bear interest at a per annum rate elected by Viper that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annummajor ratings agencies in the caseU.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit ratings from the alternate base ratethree main credit rating agencies are as follows:

•Standard and from 1.75% to 2.75% per annumPoor’s Global Ratings Services (BBB-);
•Fitch Investor Services (BBB); and
•Moody’s Investor Services (Baa2).

Any rating downgrades may result in the case of LIBOR, in each case depending on the amount of loans andadditional letters of credit outstandingor cash collateral being posted under certain contractual arrangements.

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Capital Requirements

In addition to future operating expenses and working capital commitments discussed in relation to the commitment, which is defined as the lesser“—Outlook”, our primary short and long-term liquidity requirements consist primarily of the maximum credit amount and the borrowing base. Viper is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of Viper and its subsidiary’s assets.

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

Financial CovenantRequired Ratio
Ratio of total debt to EBITDAXNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under Viper’s revolving credit facility upon the occurrence and during the continuance of any event of default. Viper’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment(i) capital expenditures, (ii) payments of principal and breachesinterest on our revolving credit agreements and senior notes, (iii) payments of negativeother contractual obligations, (iv) cash commitments for dividends and financial covenants, but non-paymentrepurchases of interestsecurities, and breaches of certain affirmative covenants are subject to customary cure periods.(v) the pending Endeavor Acquisition.


2024 Capital Requirements and Sources of LiquiditySpending Plan


Our board of directors approved a 20182024 capital budget for drilling, midstream infrastructure and infrastructureenvironmental of $1.3$2.30 billion to $1.5 billion, representing an increase of 60% over our 2017 capital budget.$2.55 billion. We estimate that, of these expenditures, approximately:


•$1.1752.10 billion to $1.325$2.33 billion will be spent primarily on drilling 265 to 285 gross (244 to 263 net) horizontal wells and completing 170300 to 190320 gross (146(273 to 163291 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins; andBasins, with an average lateral length of approximately 11,500+ feet;

$125.0•Approximately $200 million to $175.0$220 million will be spent on infrastructure and othermidstream expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the year ended December 31, 2017, our aggregate capital expenditures for drilling and infrastructure were $860.7 million. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately

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forecasted. During the year ended December 31, 2017, we spent approximately $2.0 billion on acquisitions of leasehold interests, primarily related to the Brigham Resources acquisition which closed on February 28, 2017.     


The amount and timing of theseour capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. With recent improvement in oil prices, we are currently operating ten horizontal rigs and four completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget up or down in response to changes in commodity prices and overall market conditions.


Based upon currentPayments of Principal and Interest on Senior Notes

At December 31, 2023, we have total principal payments due on our outstanding senior notes, including those of Viper, of $764 million in 2026, $430 million in 2027, $73 million in 2028 and $5.3 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $310 million in 2024, $619 million cumulatively in the years from 2025 through 2026, $543 million cumulatively in the years from 2027 and 2028, and $2.9 billion cumulatively between 2029 and 2053.

Retirements of Notes

In January 2024, we opportunistically repurchased principal amounts of $22 million of our 3.125% Senior Notes due 2031 and $6 million of our 3.500% Senior Notes due 2029 in open market transactions for total cash consideration of $25 million, at an average of 89.0% of par value.

We may continue to repurchase some of our outstanding senior notes in open market purchases or in privately negotiated transactions in future periods.

Other Contractual Obligations and Commitments

At December 31, 2023, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $768 million, (ii) electrical power purchase commitments totaling $407 million (iii) asset retirement obligations totaling $245 million, (iv) electronic fracturing fleet and related power generation services commitments totaling $93 million and (v) minimum purchase commitments for quantities of sand used in our drilling operations totaling $70 million. We expect to make aggregate payments of approximately $252 million for these commitments during 2024. See Note 6—Asset Retirement Obligations and Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for further discussion of these and other contractual obligations and commitments.

We and Five Point currently anticipate collectively contributing $500 million in follow-on capital to fund future Deep Blue growth projects and acquisitions.

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Return of Capital Commitment

Beginning in the first quarter of 2024, our board of directors has approved a reduction in our return of capital commitment to at least 50% from 75% of our quarterly free cash flow to our shareholders through repurchases under our share repurchase program, base dividends and variable dividends. The remainder of our free cash flow will be used primarily to reduce debt. On February 11, 2024, our board of directors approved an increase in our annual base dividend to $3.60 per share of common stock and, on February 16, 2024, our board of directors declared a combined base and variable dividend for the fourth quarter of 2023 of $3.08 per share of common stock.

Free cash flow is a non-GAAP financial measure. As used by us, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and other adjustments as determined by us. We believe that free cash flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas priceproperties across periods on a consistent basis.

Future base and production expectationsvariable dividends are at the discretion of our board of directors, and the board of directors may change the dividend amount from time to time based on our outlook for 2018,commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors. We can provide no assurance that dividends will be authorized or declared in the future or as to the amount and type of any future dividends. Any future dividends, whether base or variable, if declared and paid, will by their nature fluctuate based on our free cash flow, which will depend on a number of factors beyond our control, including commodity prices.

As of February 16, 2024, we believe thathave repurchased 19.3 million shares of our common stock for a total cost of $2.4 billion since the inception of the stock repurchase program, excluding excise tax. We intend to continue to opportunistically purchase shares under this repurchase program with available funds primarily from cash flow from operations and borrowingsliquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs. See Note 9—Stockholders' Equity and Earnings Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program.

Pending Endeavor Acquisition

On February 11, 2024, in connection with the execution of the Merger Agreement, we entered into a commitment letter with Citi pursuant to which Citi committed to provide an $8.0 billion senior unsecured bridge facility, subject to customary conditions. We expect to replace such commitment with permanent debt financing prior to the closing of the Endeavor Acquisition.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under ourthe indentures governing the outstanding Guaranteed Senior Notes.

Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, will be sufficientand effectively subordinated to fund our operations through year-end 2018. However,any of its existing and future cash flows are subjectsecured indebtedness, to a numberthe extent of variables, including the levelvalue of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2018 capital expenditure budget does not allocate any funds for leasehold and mineral interest acquisitions.the collateral securing such indebtedness.


We monitor and adjust our projected capital expenditures in response to success or lackThe rights of success in drilling activities, changes in prices, availabilityholders of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, weGuaranteed Senior Notes against Diamondback E&P may be requiredlimited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to curtail our drilling programs, whichlimit Diamondback E&P’s liability to the maximum amount that it could resultincur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a lossdetermination of acreage through lease expirations. In addition, wethe maximum liability of Diamondback E&P. Moreover, this provision may not be ableeffective to complete acquisitionsprotect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be favorable to us or financeset aside, in which case the capital expenditures necessary to replace our reserves. Further, ifentire liability may be extinguished.

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The following tables present summarized financial information for Diamondback Energy, Inc., as the declineparent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary, and (ii) equity in commodity prices continue, our revenues, cash flows,earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations liquidity and reserves may be materially and adversely affected.or financial position had the guarantor subsidiary operated as an independent entity.


Contractual Obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2017:
 Payments Due by Period
 2018 2019-2020 2021-2022 Thereafter Total
 (in thousands)
Secured revolving credit facility(1)
$—
 $—
 $397,000
 $—
 $397,000
Interest expense related to the secured revolving credit facility2,261
 10,522
 7,144
 —
 $19,927
Senior notes—
 —
 —
 1,000,000
 $1,000,000
Interest expense related to the senior notes(2)
50,625
 101,250
 101,250
 108,475
 $361,600
Viper's secured revolving credit facility(1)
—
 —
 93,500
 —
 $93,500
Interest and commitment fees under Viper's credit agreement(3)
1,149
 2,299
 2,107
 —
 $5,555
Asset retirement obligations (4)
1,163
 —
 —
 20,122
 $21,285
Drilling commitments(5)
21,882
 10,082
 —
 —
 $31,964
Sand supply agreements—
 18,000
 18,000
 9,000
 $45,000
Operating lease obligations(6)
3,581
 6,234
 4,648
 7,973
 $22,436
Fasken Center office building7)
99,000
 —
 —
 —
 $99,000
 $179,661

$148,387

$623,649

$1,145,570
 $2,097,267
December 31, 2023
Summarized Balance Sheets:(In millions)
(1)Assets:Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees
Current assets$1,269 
Property and equipment, net$20,780 
Other noncurrent assets$28 
Liabilities:
Current liabilities$1,974 
Intercompany accounts payable, under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.non-guarantor subsidiary$2,217 
Long-term debt$5,544 
Other noncurrent liabilities$2,835 

Year Ended December 31, 2023
(2)Summarized Statement of Operations:Interest represents the scheduled cash payments on the senior notes.
(In millions)
(3)RevenuesIncludes only the minimum amount of interest and commitment fees due which, as of December 31, 2017, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement.
$6,959 
(4)Income (loss) from operationsAmounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to

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future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 6 of the notes to our consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
$3,590 
(5)Net income (loss)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2017.$2,395 
(6)Operating lease obligations represent future commitments for building and vehicle leases.
(7)Fasken Center office buildings represents the amount we paid on January 31, 2018 at the closing of this transaction. The Fasken building contains our corporate offices.


Critical Accounting PoliciesEstimates


The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Use of Estimates


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

statements and the reported amounts of revenues and expenses during the reporting period. We evaluate theseour estimates and assumptions on an ongoing basis, using historical experience, consultationa regular basis. Critical accounting estimates are those estimates made in accordance with expertsgenerally accepted accounting principles that involve a significant level of estimation uncertainty and other methods we consider reasonable inhave had or are reasonably likely to have a material impact on the particular circumstances. Nevertheless, actualfinancial condition or results may differ significantly from our estimates.of operations of the registrant. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject

We consider the following to suchbe our most critical accounting estimates and assumptions includehave reviewed these critical accounting estimates with the Audit Committee of proved oilour board of directors.

Oil and gas reservesNatural Gas Accounting and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.Reserves

Method of accounting for oil and natural gas properties


We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred inaccounting, which is dependent on the acquisition, explorationestimation of proved reserves to determine the rate at which we record depletion on our oil and developmentnatural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired proved oil and natural gas properties including mineral and royalty interests. As such, we consider the costsestimation of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.be a critical accounting estimate.

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



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Oil and natural gas reserve quantities and standardized measureengineering is a subjective process of future net revenue

Our independent engineers and technical staff prepare our estimatesestimating underground accumulations of oil and natural gas reservesthat cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Proved oil and natural gas reserve estimates and their associated future net revenues. The SEC has defined proved reservescash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers as the estimated quantities of oilDecember 31, 2023 and gas which geological2022 and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.prepared by Ryder Scott as of December 31, 2021. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include our estimate of operating and development costs, anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time.time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reported reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortizationdepletion of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent Revisions of previous reserve estimates accounted for approximately $1.3 billion, or 15% of the change in estimating quantitiesthe standardized measure of our total reserves from December 31, 2022 to December 31, 2023. No impairments were recorded for our proved oil and natural gas reserves. Oilproperties during the years ended December 31, 2023, 2022 and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and2021. Based on the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. We accounthistorical 12-month average trailing SEC prices for oil and natural gas production imbalances using the sales method, wherebythroughout 2023 and into 2024, we are not currently projecting a liability is recorded when our volumes exceed our estimated remaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did not have any gas imbalances as of December 31, 2017, 2016 and 2015. Revenues from oil and natural gas services are recognized as services are provided.

Impairment

We use the full cost methodceiling impairment in the first quarter of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration and development2024.

Additionally, costs including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. The inclusionWe assess all items classified as unevaluated property (on an individual basis or as a group if properties are individually insignificant) at least annually for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: (i) intent to drill, (ii) remaining lease term, (iii) geological and geophysical evaluations, (iv) drilling results and activity, (v) the assignment of proved reserves, and (vi) the economic viability of development if proved reserves are assigned. At December 31, 2023, our unevaluated costs intoproperties totaled $8.7 billion, which consisted of 222,342 net undeveloped leasehold acres with approximately 8,807 net acres set to expire in 2024. We did not record any impairment on our unevaluated properties during the amortization base is expectedyear ended December 31, 2023, but any such future impairment could potentially be material to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.our consolidated financial statements.


Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

Asset retirement obligations

We measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is

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depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Commodity Derivatives


From time to time, we have used energyuse commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We recognize allexercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness. We do not use these instruments for speculative or trading purposes.

We have not designated our derivative instruments as eitherhedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value.value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.

These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of this report for additional sensitivity analysis of our open derivative positions at December 31, 2023.

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Business Combinations

We account for business combinations using the acquisition method of accounting. Accordingly, identifiable assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. Fair value (i.e., gainsestimates are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. When market-observable prices are not available to value assets and liabilities, the Company may use the cost, income, or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and furthermarket valuation approaches depending on the typequality of hedging relationship. Noneinformation available to support management’s assumptions.

The most significant assumptions relate to the estimated fair values assigned to our proved and unproved oil and natural gas properties. The assumptions made in performing these valuations include future production volumes, future commodity prices and costs, future operating and development activities, projections of our derivatives were designatedoil and gas reserves and a weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as hedging instruments duringa proxy for fair market value; for example, the years ended December 31, 2017, 2016amount a willing buyer and 2015. For derivative instruments not designatedseller would enter into in exchange for such properties. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of goodwill or discount on an acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as hedging instruments, changesinitially expected. See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the estimated fair value of assets acquired and liabilities assumed in the GRP Acquisition, Lario Acquisition, FireBird Acquisition, QEP Merger and Guidon Acquisition including any significant changes in these instruments are recognized in earnings during the period of change.

Accounting for Equity-Based Compensation

We grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Stock compensation awards are measured at fair value onestimates from the date of grantacquisition.

Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. In addition, differences between the future commodity prices when acquiring assets and are expensed,the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net of estimated forfeitures, over the required service period.earnings.


Income Taxes


The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and local tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.realized after considering all positive and negative evidence available concerning the realizability of our deferred tax assets. Positive evidence may include forecasts of future taxable income, assessment of future business assumptions and any applicable tax planning strategies available to the Company. Negative evidence may include losses in recent years, if any, or the projection of losses in future periods. The assessment of the realizability of our deferred tax assets, including the assessment of whether a valuation allowance is required, entails that we make estimates of, and assumptions about, future events, including the pattern of reversal of taxable temporary differences and our future income from operations. Estimating future taxable income requires numerous judgments and assumptions, including projections of future operating conditions which may be impacted by volatile future prices for our oil, natural gas and natural gas production, the expected timing and quantity of future production volumes, and the impact of our commodity derivative instruments on our income.


In 2023, management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards, resulted in recognition of a deferred income tax benefit of $7 million for an increase in the portion of Viper’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. Viper retained a partial valuation allowance on its deferred tax assets due primarily to potential future volatility in commodity prices and an inherent lack of visibility to certain underlying operator activity for more than relatively short periods of time, which could impact the likelihood of future realizability. As of December 31, 2023, Viper had a deferred tax asset of $170 million offset by an allowance of $114 million. Any changes in the positive or negative evidence evaluated when determining if Viper’s deferred tax assets will be realized, including projected future income, could result in a material change to our consolidated financial statements. In addition, the determination to maintain a valuation allowance on certain tax attributes acquired from QEP and certain state NOL carryforwards which the Company does not believe are realizable prior to expiration was based on an evaluation of available positive and negative evidence, including the annual limitation imposed by Section 382 of the
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Code subsequent to an ownership change and the anticipated timing of reversal of the Company’s deferred tax liabilities in the applicable jurisdictions. As of December 31, 2023, our balance of taxable temporary differences anticipated to reverse within the carryforward period provides significant positive evidence for the determination that our remaining deferred tax assets are more likely than not to be realized. Any change in the positive or negative evidence evaluated when determining if our deferred tax assets will be realized, including projected future taxable income primarily related to the excess of book carrying value over tax basis of our oil and natural gas properties, could result in a material change to our consolidated financial statements.

The accruals for deferred tax assets and liabilities are often based on uncertain tax positions and assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. At December 31, 2023, we had no uncertain tax positions, however, material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Recent Accounting Pronouncements


Recently Issued Pronouncements

In May 2014, theSee Note 2—Summary of Significant Accounting Policies in Item 8. Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAPStatements and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.

We will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. We have reviewed various contracts that represent our material revenue streams and determined that there will be no impact to our financial position, results of operations or liquidity. Upon adoptionSupplementary Data of this Accounting Standards Update, we willreport for recent accounting pronouncements not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoptionyet adopted, if any.

Off-Balance Sheet Arrangements

See Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this Accounting Standards Update, we will not be required to alter our existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by us. We do not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how we present information regarding our revenue streams as compared to existing GAAP.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update

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requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Viper will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Viper’s Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. We will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financial statements.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. We adopted this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financial statements.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on our financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. We believe the primary impact of adopting this standard will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have a material impact on our consolidated financial statements since we do not have a history of credit losses.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended December 31, 2017, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

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Off-balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2017. Please read Note 15 included in Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K,report for a discussion of our significant commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Commodity Price Risk


Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years,years. Although demand and market prices for oil and natural gas have recently increased, we expect thiscannot predict events, including the outcome of the war in Ukraine and Israel-Hamas war, rising interest rates, global supply chain disruptions, a potential economic downturn or recession that may lead to future price volatility and the near term energy outlook remains subject to continue inheightened levels of uncertainty. Further, the future. The prices we receive for production depend on many other factors outside of our control.


We use price swap derivatives, including swaps, basis swaps, androll swaps, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX WTI and Crude Oil Brent and with natural gas derivative settlements based on NYMEX Henry Hub.

At December 31, 2017 and 2016,2023, we had a net liability commodity derivative position of $106.7$27 million and $22.6 million, respectively, related to our commodity price swap and price basis swaprisk derivatives. Utilizing actual derivative contractual volumes under our fixedcommodity price swaps and fixed price basis swapsderivatives as of December 31, 2017,2023, a 10% increase in forward curves associated with the underlying commodity would have increaseddecreased the net liability position by $10 million to $180.2 million, an increase of $74.1$17 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreasedincreased the net liability derivative position by $10 million to $32.1 million, a decrease of $74.1$37 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.


For additional information on our open commodity derivative instruments at December 31, 2023, see Note 12—Derivatives in Item 8. Financial Statements and Supplementary Data of this report.

Counterparty and Customer Credit Risk


Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $73.0 million at December 31, 2017) anddue to the concentration of receivables from the sale of our oil and natural gas production (approximately $158.6$654 million at December 31, 2017)2023), and to a lesser extent, receivables resulting from joint interest receivables (approximately $122 million at December 31, 2023).


We are subject to credit risk due to the concentration
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Table of our oil and natural gas receivables with several significant customers. Contents
We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us ordue to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods.


Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2017, we had three customers that represented approximately 74% of our total joint operations receivables. At December 31, 2016, we had three customer that represented approximately 75% of our total joint operations receivables.


Interest Rate Risk


We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The termsfacilities and changes in the fair value of our revolvingfixed rate debt. Outstanding borrowings under the credit facility provide foragreement bear interest on borrowings at a floatingper annum rate equal to an alternative base rate (which is equal toelected by Diamondback E&P. At December 31, 2023, the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25%0.125% to 1.25%1.000% per annum in the case of the

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alternative alternate base rate, and from 1.25%1.125% to 2.25%2.000% per annum in the case of LIBOR,Adjusted Term SOFR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $4.0 million based on the $397.0pricing level. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecure debt. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at December 31, 2023, see Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report.

Historically, we have at times used interest rates swaps to manage our exposure to (i) interest rate changes on our floating-rate date, and (ii) fair value changes on our fixed rate debt. At December 31, 2023, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of changes to the fair value of our fixed rate senior notes due to changes in market interest rates through December 2029. We pay an average variable rate of interest for these swaps based on three month SOFR plus 2.1865% and receive a fixed interest rate of 3.50% from our counterparties. At December 31, 2023, our receive-fixed, pay-variable interest rate swaps were in a net liability position of $163 million, outstandingand the weighted average variable rate was 5.86%. For additional information on our interest rate swaps, see Note 12—Derivatives in the aggregate under our revolving credit facility asItem 8. Financial Statements and Supplementary Data of such date.this report.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page F-1 of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2017, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2017, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the year ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2017.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2017. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2017, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Diamondback Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 14, 2018 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
February 14, 2018


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ITEM 9B.     OTHER INFORMATION

None.

PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section at http://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11.     EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2017.


ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)
(a)Documents included in this report:
1. Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
F-166
Consolidated Balance Sheets
F-269
Consolidated Statements of Operations and Comprehensive Income
F-370
Consolidated Statements of Stockholders' Equity
F-471
Consolidated Statements of Cash Flows
F-572
Notes to Consolidated Financial Statements
F-773
2. Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.


65
3. Exhibits
Exhibit NumberDescription
2.1#
Purchase and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
2.2#
Purchase and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
2.3#
Purchase and Sale Agreement by and among Rio Oil and Gas, LLC, Rio Oil and Gas (Permian) LLC, Rio Oil and Gas (OPCO), LLC, Bluestem Energy, LP, Bluestem Energy Partners, LP, Bluestem Energy Holdings, LLC, Bluestem Energy Assets, LLC, Bluestem Acquisitions, LLC, BC Operating, Inc., Crown Oil Partners V, LP and Crump Energy Partners II, LLC, as sellers, and Diamondback E&P LLC, as buyer, dated July 18, 2014 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on July 21, 2014).
2.4#
Purchase and Sale Agreement, dated as of December 13, 2016, by and among Brigham Resources Operating, LLC and Brigham Resources Midstream, LLC, as sellers, and Diamondback E&P LLC and Diamondback Energy, Inc., as buyers (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 14, 2016).
3.1
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.2
Certificate of Amendment No. 1 of the Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2016).
3.3
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.1
Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
4.2
Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.3
Indenture, dated as of October 28, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 4.750 % Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 2, 2016).
4.4
Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2016).
4.5
First Supplemental Indenture, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018).
4.6
Registration Rights Agreement, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018).
4.7
Registration Rights Agreement, dated as of February 28, 2017, among Diamondback Energy, Inc., Brigham Resources, LLC, Brigham Resources Operating, LLC and Brigham Resources Upstream Holdings, LP. (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001.35700, filed by the Company with the SEC on March 6, 2017).
10.1
Diamondback Energy, Inc. 2016 Amended and Restated Equity Incentive Plan (incorporated by reference to Appendix A to Schedule DEFA 14A filed by the Company with the SEC on May 25, 2016).
10.2+
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).


3. Exhibits
10.3+
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.4+
Form of Director and Officer Indemnification Agreement (incorporated by reference to
Exhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.5
Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
10.6
Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
10.7+
Amended and Restated Employment Agreement, dated April 24, 2014, effective as of April 18, 2014, by and between Travis D. Stice and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-035700, filed by the Company with the SEC on May 9, 2014 ).
10.8+
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Teresa Dick and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
10.9+
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Michael Hollis and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
10.10+
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Jeff White and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
10.11+
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Russell Pantermuehl and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-035700, filed by the Company with the SEC on May 9, 2014 ).
10.12+
2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on April 2, 2014).
10.13+
Form of Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
10.14+
Form of Performance-Based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
10.15
Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).
10.16
Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.17
Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.18
Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.19
Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).


3. Exhibits
10.20
Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
10.21
Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.22
Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.23
Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.24
Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.25
Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
10.26
Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company (incorporated by reference to Exhibit 10.26 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.27
Master Drilling Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
10.28
Master Field Services Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
10.29
First Amendment to Master Field Services Agreement, dated as of February 21, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.35 to the Form 10-K, file No. 001-35700, filed by the Company with the SEC on March 1, 2013).
10.30+
Form of Amendment to Restricted Stock Unit Certificate (incorporated by reference to Exhibit 10.38 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).
10.31
Lease Amendment No. 6 effective May 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.39 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).
10.32
Lease Amendment No. 7 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).
10.33
Lease Amendment No. 8 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).
10.34
Lease Amendment No. 9 effective August 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
10.35
Lease Amendment No. 10 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
10.36
Second Amended and Restated Credit Agreement, dated as of November 1, 2103, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).


3. Exhibits
10.37
First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, by and among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014).
10.38
Second Amendment to the Second Amended and Restated Credit Agreement, dated as of November 13, 2014, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, the guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 18, 2014).
10.39
Third Amendment, dated as of June 21, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 27, 2016).
10.40
Fourth Amendment, dated as of December 15, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 20, 2016).
10.41
Fifth Amendment, dated as of November 28, 2017, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 4, 2017).
10.42
Senior Secured Revolving Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, Wells Fargo Bank, National Association, as the administrative agent, sole book runner and lead arranger, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-36505, filed by Viper Energy Partners LP on July 14, 2014).
10.43
Contribution Agreement by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP, dated as of June 17, 2014 (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by Viper Energy Partners LP with the SEC on May 7, 2014).
10.44
First Amendment, dated as of August 15, 2014, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 10, 2015).
10.45
Second Amendment, dated as of May 22, 2015, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 6, 2015).
10.46
Third Amendment, dated as of June 21, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed June 27, 2016).
10.47
Fourth Amendment, dated as of October 28, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed on November 3, 2016).
10.48
Fifth Amendment, dated as of November 28, 2017, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy Partners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed on December 4, 2017).
10.49
Lease Amendment No. 11 effective July 31, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).


3. Exhibits
10.50
Lease Amendment No. 12 effective October 23, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
10.51
Lease Amendment No. 13 effective October 30, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
10.52
Lease Amendment No. 14 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
10.53
Lease Amendment No. 15 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
10.54
Lease Amendment No. 16 effective April 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
10.55
Lease Amendment No. 17 effective June 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
21.1*
Subsidiaries of the Registrant.
23.1*
Consent of Grant Thornton LLP.
23.2*
Consent of Ryder Scott Company, L.P. with respect to the Diamondback Energy, Inc. reserve report included as Exhibit 99.1.
23.3*
Consent of Ryder Scott Company, L.P. with respect to the Viper Energy Partners LP reserve report included as Exhibit 99.2.
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
99.1*
Report of Ryder Scott Company, L.P., dated January 18, 2018, with respect to an estimate of the proved reserves, future production and income attributable to certain leasehold interests of Diamondback Energy, Inc. as of December 31, 2017.
99.2*
Report of Ryder Scott Company, L.P., dated January 18, 2018, with respect to an estimate of the proved reserves, future production and income attributable to certain royalty interests of Viper Energy Partners LP, a subsidiary of Diamondback Energy, Inc., as of December 31, 2017.
101.INS*XBRL Instance Document.
101.SCH*XBRL Taxonomy Extension Schema Document.
101.CAL*XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.


_______________
*Filed herewith.
**The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
+Management contract, compensatory plan or arrangement.
#The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY
None


SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DIAMONDBACK ENERGY, INC.
Date:February 14, 2018
/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
(Principal Executive Officer)

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ Steven E. WestChairman of the Board and DirectorFebruary 14, 2018
Steven E. West
/s/ Travis D. SticeChief Executive Officer and DirectorFebruary 14, 2018
Travis D. Stice(Principal Executive Officer)
/s/ Michael P. CrossDirectorFebruary 14, 2018
Michael P. Cross
/s/ David L. HoustonDirectorFebruary 14, 2018
David L. Houston
/s/ Mark L. PlaumannDirectorFebruary 14, 2018
Mark L. Plaumann
/s/ Teresa L. DickChief Financial Officer, Senior Vice President, and Assistant SecretaryFebruary 14, 2018
Teresa L. Dick(Principal Financial and Accounting Officer)


S-1

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors and Stockholders
Diamondback Energy, Inc.


Opinion on the financial statements


We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the(the “Company”) as of December 31, 20172023 and 2016, and2022, the related consolidated statements of operations and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017,2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.


We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017,2023, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated February 14, 201822, 2024 expressed an unqualified opinion.


Basis for opinion


These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.


We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included assessingevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.



Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Estimation of proved reserves as it relates to the calculation and recognition of depletion expense and the valuation of acquired reserves in connection with the acquisition of Lario’s oil and natural gas properties and GRP’s mineral and royalty interests

As described further in Note 2 to the financial statements, the Company accounts for its oil and natural gas properties using the full cost method of accounting, which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense. Additionally, as described in Note 4 to the financial statements, the Company acquired significant oil and natural gas properties and mineral and royalty interests during the year through the Lario and GRP Acquisitions, respectively. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the timing and volumetric amounts of production and corresponding decline rate of producing properties associated with the Company’s development plan. In addition, the estimation of proved reserves is impacted by management’s judgments and estimates regarding the financial performance of wells to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions. For acquired reserves, management also utilizes an estimated fair value pricing model in determining the corresponding value of proved reserves. We identified the estimation of proved reserves attributable to oil and natural gas properties, including acquired proved reserves in the Lario and GRP Acquisitions, due to its impact on depletion expense and acquisition accounting, as a critical audit matter.

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The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense and the fair value of acquired oil and natural gas properties. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

•We tested the design and operating effectiveness of key controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and management’s estimation of the fair value of the acquired oil and natural gas properties in the Lario and GRP Acquisitions.

•We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and independent petroleum engineering specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the year-end reserve report audited by the independent petroleum engineering specialists.

•Identified inputs and assumptions that were significant to the period end determination of proved reserve volumes and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Compared the estimated pricing and pricing differentials used in the reserve report to actual realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

◦Assessed operating cost inputs by comparing the forecasted amount to historical actual costs;

◦Assessed the reasonableness of forecasted capital expenditures by comparing drilling forecasts applied in the reserve report to recent, actual drilling costs;

◦Assessed forecasted production estimates by (i) comparing prior year forecasted production amounts to current year actual results and (ii) comparing forecasted production amounts in the current year reserve report to the actual historical production amounts in the current year, in total and for a sample of individual wells;

◦Vouched, on a sample basis, the working and net revenue interests used in the reserve report to underlying land and division order records;

◦Obtained evidence supporting the amount of development of proved undeveloped properties reflected in the reserve report and compared future development plans to historical conversion rates to evaluate the likelihood of development related to the proved undeveloped properties; and

◦Applied analytical procedures on inputs to the reserve report by comparing to historical actual results and to the prior year reserve report.

•Identified inputs and assumptions that were significant to the estimated fair value of the acquired oil and natural gas properties in the Lario and GRP Acquisitions and tested management’s process of determining the significant inputs and assumptions, as follows:

◦Evaluated the appropriateness of fair value pricing, including pricing differentials, used in the fair value reserve report of proved reserves by comparing the pricing forecast to published product pricing as of the acquisition closing dates and pricing differentials to actual historical realized pricing;

◦Utilized a valuation specialist to evaluate whether the Company’s valuation methodology of the Lario Acquisition was reasonable and for certain inputs and assumptions, evaluated the process used to develop the estimate and developed an independent expectation of the estimate to evaluate its reasonableness;

◦Evaluated the appropriateness of the future operating cost and capital expenditure assumptions used in the Lario Acquisition fair value reserve report by comparing forecasted amounts to historical operating costs and capital expenditures of similarly located properties;

◦Compared, on a sample basis, the working and net revenue interests used in the fair value reserve report to the purchase and sale agreements;

◦Tested the accuracy of forecasted production estimates in the fair value reserve reports by comparing forecasted production amounts to the actual historical production amounts for a sample of individual wells;

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◦Applied analytical procedures on the Lario Acquisition and GRP Acquisition fair value reserve reports’ forecasted production by comparing to the quarter-end and year-end, respectively, reserve reports’ forecasted production of the acquired proved properties; and

◦Compared the unproved acreage value allocated, on a per acre basis, to other recent acquisitions in the same or similar locations.

/s/ GRANT THORNTON LLP


We have served as the Company’s auditor since 20092009.


Oklahoma City, Oklahoma
February 14, 201822, 2024




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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets


December 31,
20232022
(In millions, except par value and share amounts)
Assets
Current assets:
Cash and cash equivalents$582 $157 
Restricted cash3 7 
Accounts receivable:
Joint interest and other, net192 104 
Oil and natural gas sales, net654 618 
Income tax receivable1 284 
Inventories63 67 
Derivative instruments17 132 
Prepaid expenses and other current assets109 23 
Total current assets1,621 1,392 
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,659 million and $8,355 million excluded from amortization at December 31, 2023 and December 31, 2022, respectively)42,430 37,122 
Other property, equipment and land673 1,481 
Accumulated depletion, depreciation, amortization and impairment(16,429)(14,844)
Property and equipment, net26,674 23,759 
Funds held in escrow— 119 
Equity method investments529 566 
Assets held for sale— 158 
Derivative instruments1 23 
Deferred income taxes, net45 64 
Investment in real estate, net84 86 
Other assets47 42 
Total assets$29,001 $26,209 
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade$261 $127 
Accrued capital expenditures493 480 
Current maturities of long-term debt— 10 
Other accrued liabilities475 399 
Revenues and royalties payable764 619 
Derivative instruments86 47 
Income taxes payable29 34 
Total current liabilities2,108 1,716 
Long-term debt6,641 6,238 
Derivative instruments122 148 
Asset retirement obligations239 336 
Deferred income taxes2,449 2,069 
Other long-term liabilities12 12 
Total liabilities11,571 10,519 
Commitments and contingencies (Note 15)  
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 178,723,871 and 179,840,797 shares issued and outstanding at December 31, 2023 and December 31, 2022, respectively2 2 
Additional paid-in capital14,142 14,213 
Retained earnings (accumulated deficit)2,489 801 
Accumulated other comprehensive income (loss)(8)(7)
Total Diamondback Energy, Inc. stockholders’ equity16,625 15,009 
Non-controlling interest805 681 
Total equity17,430 15,690 
Total liabilities and stockholders' equity$29,001 $26,209 


 December 31,
 2017 2016
 (In thousands, except share amounts)
Assets   
Current assets:   
Cash and cash equivalents$112,446
 $1,666,574
Restricted cash—
 500
Accounts receivable:   
Joint interest and other73,038
 49,476
Oil and natural gas sales158,575
 70,349
Related party—
 297
Inventories9,108
 1,983
Derivative instruments531
 —
Prepaid expenses and other4,903
 2,987
Total current assets358,601
 1,792,166
Property and equipment:   
Oil and natural gas properties, full cost method of accounting ($4,105,865 and $1,730,519 excluded from amortization at December 31, 2017 and 2016, respectively)9,232,694
 5,160,261
Midstream assets191,519
 8,362
Other property, equipment and land80,776
 58,290
Accumulated depletion, depreciation, amortization and impairment(2,161,372) (1,836,056)
Net property and equipment7,343,617
 3,390,857
Funds held in escrow6,304
 121,391
Derivative instruments—
 709
Other assets62,463
 44,557
Total assets$7,770,985
 $5,349,680
Liabilities and Stockholders’ Equity   
Current liabilities:   
Accounts payable-trade$94,590
 $47,648
Accounts payable-related party—
 1
Accrued capital expenditures221,256
 60,350
Other accrued liabilities92,512
 55,330
Revenues and royalties payable68,703
 23,405
Derivative instruments100,367
 22,608
Total current liabilities577,428
 209,342
Long-term debt1,477,347
 1,105,912
Derivative instruments6,303
 —
Asset retirement obligations20,122
 16,134
Deferred income taxes108,048
 —
Total liabilities2,189,248
 1,331,388
Commitments and contingencies (Note 15)

 

Stockholders’ equity:   
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017; 90,143,934 issued and outstanding at December 31, 2016982
 901
Additional paid-in capital5,291,011
 4,215,955
Accumulated deficit(37,133) (519,394)
Total Diamondback Energy, Inc. stockholders’ equity5,254,860
 3,697,462
Non-controlling interest326,877

320,830
Total equity5,581,737
 4,018,292
Total liabilities and equity$7,770,985
 $5,349,680
See accompanying notes to consolidated financial statements.

F-2
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Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Operations and Comprehensive Income




Year Ended December 31,
202320222021
(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales$7,279 $7,660 $5,396 
Natural gas sales262 858 569 
Natural gas liquid sales687 1,048 782 
Sales of purchased oil111 — — 
Other operating income73 77 50 
Total revenues8,412 9,643 6,797 
Costs and expenses:
Lease operating expenses872 652 565 
Production and ad valorem taxes525 611 425 
Gathering, processing and transportation287 258 212 
Purchased oil expense111 — — 
Depreciation, depletion, amortization and accretion1,746 1,344 1,275 
General and administrative expenses150 144 146 
Merger and integration expenses11 14 78 
Other operating expenses140 112 95 
Total costs and expenses3,842 3,135 2,796 
Income (loss) from operations4,570 6,508 4,001 
Other income (expense):
Interest expense, net(175)(159)(199)
Other income (expense), net68 (5)13 
Gain (loss) on derivative instruments, net(259)(586)(848)
Gain (loss) on extinguishment of debt(4)(99)(75)
Income (loss) from equity investments, net48 77 15 
Total other income (expense), net(322)(772)(1,094)
Income (loss) before income taxes4,248 5,736 2,907 
Provision for (benefit from) income taxes912 1,174 631 
Net income (loss)3,336 4,562 2,276 
Net income (loss) attributable to non-controlling interest193 176 94 
Net income (loss) attributable to Diamondback Energy, Inc.$3,143 $4,386 $2,182 
Earnings (loss) per common share:
Basic$17.34 $24.61 $12.24 
Diluted$17.34 $24.61 $12.24 
Weighted average common shares outstanding:
Basic179,999 176,539 176,643 
Diluted179,999 176,539 176,643 
Comprehensive income (loss):
Net income (loss) attributable to Diamondback Energy, Inc.$3,143 $4,386 $2,182 
Other comprehensive income (loss), net of tax:
Pension and postretirement benefit plans(1)(7)— 
Comprehensive income (loss) attributable to Diamondback Energy, Inc$3,142 $4,379 $2,182 

 Year Ended December 31,
 2017 2016 2015
 (In thousands, except per share amounts)
Revenues:     
Oil sales$1,044,017
 $470,528
 $405,715
Natural gas sales52,210
 22,506
 19,592
Natural gas liquid sales90,048
 34,073
 21,426
Lease bonus11,764
 —
 —
Midstream services7,072
 —
 —
Total revenues1,205,111
 527,107
 446,733
Costs and expenses:     
Lease operating expenses126,524
 82,428
 82,625
Production and ad valorem taxes73,505
 34,456
 32,990
Gathering and transportation12,834
 11,606
 6,091
Midstream services10,409
 —
 —
Depreciation, depletion and amortization326,759
 178,015
 217,697
Impairment of oil and natural gas properties—
 245,536
 814,798
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $25,537, $26,453 and $18,529 for the year ended December 31, 2017, 2016 and 2015, respectively)48,669
 42,619
 31,968
Asset retirement obligation accretion1,391
 1,064
 833
Total costs and expenses600,091
 595,724
 1,187,002
Income (loss) from operations605,020
 (68,617) (740,269)
Other income (expense):     
Interest expense, net(40,554) (40,684) (41,510)
Other income, net10,235
 3,064
 728
Gain (loss) on derivative instruments, net(77,512) (25,345) 31,951
Loss on extinguishment of debt—
 (33,134) —
Total other expense, net(107,831) (96,099) (8,831)
Income (loss) before income taxes497,189
 (164,716) (749,100)
Provision for (benefit from) income taxes(19,568) 192
 (201,310)
Net income (loss)516,757
 (164,908) (547,790)
Net income attributable to non-controlling interest34,496
 126
 2,838
Net income (loss) attributable to Diamondback Energy, Inc.$482,261
 $(165,034) $(550,628)
      
Earnings per common share:     
Basic$4.95
 $(2.20) $(8.74)
Diluted$4.94
 $(2.20) $(8.74)
Weighted average common shares outstanding:     
Basic97,458
 75,077
 63,019
Diluted97,688
 75,077
 63,019


See accompanying notes to consolidated financial statements.

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated StatementStatements of Stockholders’ Equity



Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Accumulated
Other
Comprehensive
Income (Loss)		Non-Controlling Interest
SharesAmountTotal
($ in millions, shares in thousands)
Balance at December 31, 2020158,088 $2 $12,656 $(3,864)$— $1,010 $9,804 
Issuance of common units - Viper Energy Partners LP— — — — — 337 337 
Unit-based compensation— — — — — 11 11 
Distribution equivalent rights payments— — — (4)— (2)(6)
Common stock issued for acquisitions22,795 — 1,727 — — — 1,727 
Stock-based compensation— — 60 — — — 60 
Cash paid for tax withholding on vested equity awards— — (6)— — (2)(8)
Repurchased shares under buyback program(4,128)— (431)— — — (431)
Repurchased units under buyback programs— — — — — (94)(94)
Distributions to non-controlling interest— — — — — (112)(112)
Dividend paid— — — (312)— — (312)
Exercise of stock options and vesting of restricted stock units796 — 12 — — — 12 
Change in ownership of consolidated subsidiaries, net— — 66 — — (85)(19)
Net income (loss)— — — 2,182 — 94 2,276 
Balance at December 31, 2021177,551 2 14,084 (1,998)— 1,157 13,245 
Unit-based compensation— — — — — 8 8 
Distribution equivalent rights payments— — — (15)— (1)(16)
Stock-based compensation4 — 68 — — — 68 
Cash paid for tax withholding on vested equity awards(11)— (16)— — (3)(19)
Repurchased shares under buyback program(8,694)— (1,098)— — — (1,098)
Repurchased units under buyback programs— — — — — (153)(153)
Common stock issued for acquisition10,273 — 1,220 — — (344)876 
Distributions to non-controlling interest— — — — — (217)(217)
Dividend paid— — — (1,572)— — (1,572)
Exercise of stock options and issuance of restricted stock units and awards718 — 1 — — — 1 
Change in ownership of consolidated subsidiaries, net— — (46)— — 58 12 
Other comprehensive income (loss), net of tax— — — — (7)— (7)
Net income (loss)— — — 4,386 — 176 4,562 
Balance at December 31, 2022179,841 2 14,213 801 (7)681 15,690 
Viper common stock issued for acquisition— — — — — 255 255 
Viper equity-based compensation— — — — — 1 1 
Distribution equivalent rights payments— — — (11)— — (11)
Stock-based compensation394 — 79 — — — 79 
Cash paid for tax withholding on vested equity awards(146)— (20)— — — (20)
Repurchased shares under buyback program(6,238)— (840)— — — (840)
Repurchased shares/units under Viper's buyback programs— — — — — (95)(95)
Common stock issued for acquisition4,330 — 633 — — — 633 
Dividends/distributions to non-controlling interest— — — — — (129)(129)
Dividend paid— — — (1,444)— — (1,444)
Exercise of stock options and issuance of restricted stock units and awards543 — — — — — — 
Change in ownership of consolidated subsidiaries, net— — 77 — — (101)(24)
Other comprehensive income (loss), net of tax— — — — (1)— (1)
Net income (loss)— — — 3,143 — 193 3,336 
Balance at December 31, 2023178,724 $2 $14,142 $2,489 $(8)$805 $17,430 

 Common Stock Additional Paid-in Capital Retained Earnings (Accumulated Deficit) Non-Controlling Interest  
 SharesAmount    Total
           
 (In thousands)
Balance December 31, 201456,888
$569
 $1,554,174
 $196,268
 $234,202
 $1,985,213
Unit-based compensation —
 —
 —
 3,929
 3,929
Distribution to non-controlling interest —
 —
 —
 (7,968) (7,968)
Stock-based compensation —
 20,645
 —
 —
 20,645
Common shares issued in public offering, net of offering costs9,488
94
 649,979
 —
 —
 650,073
Exercise of stock options and vesting of restricted stock units421
5
 4,866
 —
 —
 4,871
Net income (loss) —
 —
 (550,628) 2,838
 (547,790)
Balance December 31, 201566,797
668
 2,229,664
 (354,360) 233,001
 2,108,973
Net proceeds from issuance of common units - Viper Energy Partners LP —
 —
 —
 93,462
 93,462
Unit-based compensation —
 —
 —
 3,815
 3,815
Distribution to non-controlling interest —
 —
 —
 (9,574) (9,574)
Stock-based compensation —
 29,717
 —
 —
 29,717
Common shares issued in public offering, net of offering costs23,000
229

1,956,079
 —
 —
 1,956,308
Exercise of stock options and awards of restricted stock347
4
 495
 —
 —
 499
Net income (loss) —
 —
 (165,034) 126
 (164,908)
Balance December 31, 201690,144
901
 4,215,955
 (519,394) 320,830
 4,018,292
Net proceeds from issuance of common units - Viper Energy Partners LP —
 —
 —
 369,896
 369,896
Unit-based compensation —
 —
 —
 2,395
 2,395
Common units issued for acquisition —
 —
 —
 3,050
 3,050
Stock-based compensation —
 31,783
 —
 —
 31,783
Distribution to non-controlling interest —
 —
 —
 (41,367) (41,367)
Common shares issued in public offering, net of offering costs —

14
 —
 —
 14
Common shares issued for acquisition7,686
77
 809,096
 —
 —
 809,173
Exercise of stock options and awards of restricted stock337
4
 355
 —
 —
 359
Change in ownership of consolidated subsidiaries, net —
 233,808
 —
 (362,423) (128,615)
Net income —
 —
 482,261
 34,496
 516,757
Balance December 31, 201798,167
$982
 $5,291,011
 $(37,133) $326,877
 $5,581,737











See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows



Year Ended December 31,
202320222021
(In millions)
Cash flows from operating activities:
Net income (loss)$3,336 $4,562 $2,276 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes378 720 606 
Depreciation, depletion, amortization and accretion1,746 1,344 1,275 
(Gain) loss on extinguishment of debt4 99 75 
(Gain) loss on derivative instruments, net259 586 848 
Cash received (paid) on settlement of derivative instruments(110)(850)(1,247)
(Income) loss from equity investment, net(48)(77)(15)
Equity-based compensation expense54 55 51 
Other5 85 39 
Changes in operating assets and liabilities:
Accounts receivable(71)(47)(196)
Income tax receivable283 (283)152 
Prepaid expenses and other current assets(89)21 20 
Accounts payable and accrued liabilities57 (47)(41)
Income taxes payable(5)17 — 
Revenues and royalties payable123 156 148 
Other(2)(16)(47)
Net cash provided by (used in) operating activities5,920 6,325 3,944 
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties(2,582)(1,854)(1,457)
Additions to midstream assets(119)(84)(30)
Property acquisitions(2,013)(1,675)(787)
Proceeds from sale of assets1,407 327 820 
Other(16)(44)(85)
Net cash provided by (used in) investing activities(3,323)(3,330)(1,539)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities4,779 5,204 1,313 
Repayments under credit facilities(4,668)(5,551)(1,000)
Proceeds from senior notes400 2,500 2,200 
Repayment of senior notes(134)(2,410)(3,193)
Proceeds from (repayments to) joint venture— (74)(20)
Premium on extinguishment of debt— (63)(178)
Repurchased shares under buyback program(840)(1,098)(431)
Repurchased shares/units under Viper's buyback program(95)(153)(94)
Dividends paid to stockholders(1,444)(1,572)(312)
Dividends/distributions to non-controlling interest(129)(217)(112)
Financing portion of net cash received (paid) for derivative instruments— — 22 
Other(45)(69)(36)
Net cash provided by (used in) financing activities(2,176)(3,503)(1,841)
Net increase (decrease) in cash and cash equivalents421 (508)564 
Cash, cash equivalents and restricted cash at beginning of period164 672 108 
Cash, cash equivalents and restricted cash at end of period$585 $164 $672 

 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Cash flows from operating activities:     
Net income (loss)$516,757
 $(164,908) $(547,790)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
Provision for deferred income taxes(20,567) —
 (201,545)
Impairment of oil and natural gas properties—
 245,536
 814,798
Asset retirement obligation accretion1,391
 1,064
 833
Depreciation, depletion and amortization326,759
 178,015
 217,697
Amortization of debt issuance costs3,943
 2,717
 2,601
Loss on early extinguishment of debt—
 33,134
 —
Change in fair value of derivative instruments84,240
 26,522
 112,918
Income from equity investment(657) (676) —
Equity-based compensation expense25,537
 26,453
 18,529
Gain (loss) on sale of assets, net(455) (61) 668
Changes in operating assets and liabilities:     
Accounts receivable(97,611) (35,030) 8,998
Accounts receivable-related party297
 1,294
 2,149
Restricted cash500
 —
 —
Inventories(2,245) (255) 224
Prepaid expenses and other(11,362) (709) (1,310)
Accounts payable and accrued liabilities36,762
 15,922
 802
Accounts payable and accrued liabilities-related party(2) (216) 218
Income tax payable814
 —
 —
Accrued interest(20,774) (3,161) (255)
Revenues and royalties payable45,298
 6,439
 (13,034)
Net cash provided by operating activities888,625
 332,080
 416,501
Cash flows from investing activities:     
Additions to oil and natural gas properties(792,599) (362,450) (419,241)
Additions to oil and natural gas properties-related party—
 (637) (271)
Additions to midstream assets(68,139) (1,188) —
Purchase of other property, equipment and land(22,779) (9,891) (1,213)
Acquisition of leasehold interests(1,960,591) (611,280) (437,455)
Acquisition of mineral interests(407,450) (205,721) (43,907)
Acquisition of midstream assets(50,279) —
 —
Proceeds from sale of assets65,656
 4,661
 9,739
Funds held in escrow104,087
 (121,391) —
Equity investments(188) (2,345) (2,702)
Net cash used in investing activities(3,132,282) (1,310,242) (895,050)
Cash flows from financing activities:     
Proceeds from borrowings under credit facility753,500
 164,000
 425,001
Repayment under credit facility(383,500) (89,000) (603,001)
Proceeds from senior notes—
 1,000,000
 —
Repayment of senior notes—
 (450,000) —
Premium on extinguishment of debt—
 (26,561) —
Debt issuance costs(9,296) (15,063) (526)
Public offering costs(510) (1,182) (586)



F-5
Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued




 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Proceeds from public offerings370,344
 2,051,503
 650,688
Proceeds from exercise of stock options358
 498
 4,873
Distributions to non-controlling interest(41,367) (9,574) (7,968)
Net cash provided by financing activities689,529
 2,624,621
 468,481
Net increase (decrease) in cash and cash equivalents(1,554,128) 1,646,459
 (10,068)
Cash and cash equivalents at beginning of period1,666,574
 20,115
 30,183
Cash and cash equivalents at end of period$112,446
 $1,666,574
 $20,115
      
Supplemental disclosure of cash flow information:     
Interest paid, net of capitalized interest$57,668
 $38,177
 $38,758
Cash paid for income taxes$—
 $192
 $267
Supplemental disclosure of non-cash transactions:     
Change in accrued capital expenditures$160,906
 $413
 $(69,460)
Capitalized stock-based compensation$8,641
 $7,079
 $6,043
Common stock issued for oil and natural gas properties$809,173
 $—
 $—
Asset retirement obligations acquired$2,432
 $3,696
 $3,159
































See accompanying notes to consolidated financial statements.

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F-6
Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements





1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION


Organization and Description of the Business


Diamondback Energy, Inc. (“Diamondback”, together with its subsidiaries (collectively referred to as “Diamondback” or the “Company”) unless the context otherwise requires), is an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on

As of December 30, 2011.

On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to31, 2023, the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4–Viper Energy Partners LP for additional information regarding the Partnership.

The wholly-owned subsidiaries of Diamondback as of December 31, 2017, include Diamondback E&P LLC (“Diamondback E&P”), a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy PartnersRattler Midstream GP LLC, a Delaware limited liability company and(“Rattler’s GP”), Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Rattler”), and QEP Resources, Inc. (“QEP”), a Delaware Corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries.

Rattler Merger

On August 24, 2022 (the “Effective Date”), the Company completed the merger with Rattler pursuant to which the Company acquired all of the approximately 38.51 million publicly held outstanding common units of Rattler in exchange for approximately 4.35 million shares of the Company’s common stock (the “Rattler Merger”). Rattler continued as the surviving entity. Following the Rattler Merger, the Company owns all of Rattler’s outstanding common units and Class B units, and Rattler GP remains the general partner of Rattler. Following the closing of the Rattler Merger, Rattler’s common units were delisted from Nasdaq and Rattler filed a certification on Form 15 with the SEC requesting the deregistration of its common units and suspension of Rattler’s reporting obligations under the Exchange Act.

The Rattler Merger was accounted for as a non-cash equity transaction resulting in increases to common stock of $44 thousand, additional paid-in-capital of $344 million, merger and integration expense of $11 million and a decrease in noncontrolling interests in consolidated subsidiaries of $344 million. For periods prior to the Effective Date, the results of operations attributable to the non-controlling interest in Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.

Viper Conversion to Corporate Structure

On November 13, 2023, the Company’s publicly traded subsidiary, Viper Energy Partners, LLC,LP completed its conversion from a Delaware limited liability company.partnership into a Delaware corporation, Viper Energy, Inc. (“Viper”) (“the Viper Conversion”). At the time of the Viper Conversion, each of the Company’s common units representing limited partnership interest in Viper Energy Partners, LP was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class A common stock of Viper Energy, Inc., and each of the Company’s Class B unit representing limited partnership interest in Viper Energy Partners, LP was converted, on a unit-for-unit basis, into one issued and outstanding, fully paid and nonassessable share of Class B common stock of Viper Energy, Inc. Viper is now a “controlled company” under the Nasdaq rules because the Company owns more than 50% of the voting power of Viper’s common stock.


Basis of Presentation


The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.


The PartnershipViper is consolidated in the Company’s financial statementsstatements. On October 31, 2023, pursuant to a common unit purchase and sale agreement entered into on September 4, 2023, Viper issued approximately 7.22 million of its common units, which were converted to shares of Viper Class A common stock at the time of the Company.Viper Conversion, to the Company at a price of $27.72 per unit for total consideration to Viper of approximately $200 million. As of December 31, 2017,2023, the Company owned approximately 64%56% of Viper’s combined outstanding Class A common stock and Class B common stock. The results of operations attributable to the non-controlling interest in Viper are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

The Company has two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and includes the activities of Viper, and (ii) the midstream operations segment, which owns and operates certain midstream infrastructure assets in the Midland and Delaware Basins of the common units ofPermian Basin. Prior to the PartnershipRattler Merger, both the upstream operations segment and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, ismidstream operations segment were considered reportable segments. Following the General PartnerRattler Merger, the Company determined only the upstream operations segment met the quantitative requirements of a reportable segment.

Reclassifications

Certain prior period amounts have been reclassified to conform to the Partnership.current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.


2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


Use of Estimates


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


Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices. For instance, war in Ukraine and Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations,fair value estimates of derivative instruments, the fair value determination of acquired assets and liabilities equity-based compensation, fair value estimates of commodity derivativesassumed, and estimates of income taxes.taxes, including deferred tax valuation allowances.

F-7


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Cash, and Cash Equivalents and Restricted Cash


The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Restricted Cash

In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow.  The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.


Accounts Receivable


Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.


Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts whenexpected losses as estimated by the Company believeswhen collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest
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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by consideringfor each type of receivable utilizing the loss-rate method, which considers a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary atexpected losses. At December 31, 2017 or December 31, 2016.2023 and 2022, the Company’s allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production were not material.


Derivative Instruments


The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company hasFor commodity derivative instruments and interest rate swaps which have not been designated its derivative instruments as hedges for accounting purposes, and, as a result,the Company marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations.

Fair Value From the second quarter of Financial Instruments

The Company’s financial instruments consist2021 through the second quarter of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates2022, the Company had certain interest rate swaps designated as fair value becausehedges under the “shortcut” method of accounting. As such, gains and losses due to changes in the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based oninterest rate swaps during those periods completely offset changes in the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (seehedged portion of the underlying debt. In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued. For additional information regarding the Company’s derivative instruments, see Note 14–Fair Value Measurements)12—Derivatives.


Oil and Natural Gas Properties


The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrativeinternal costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred.

F-8


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 7–Equity Method Investments).liquids. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.11, $11.23$10.21, $8.87 and $17.84$8.77 for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively. Depreciation, depletion and amortizationDepletion expense for oil and natural gas properties was $321.9 million, $176.4 million$1.7 billion, $1.3 billion and $216.1 million$1.2 billion for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively.


Under thisthe full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized costoil and natural gas properties net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedownwrite-down is required. During the years ended December 31, 2016 and 2015, the Company recorded impairmentsFor additional information on proved oil and natural gas properties, see Note 5—Property and Equipment.

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Table of $245.5 millionContents
Diamondback Energy, Inc. and $814.8 million, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017.Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on at least an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.


Other Property, Equipment and Land


Other property, equipment and equipmentland is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight linestraight-line method over theirthe estimated useful lives of the assets, which range from three years to fifteen30 years. Depreciation expense

Equity Method Investments

The Company accounts for its corporate joint ventures and equity investments under the equity method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 323 “Investments — Equity Method and Joint Ventures.” The Company applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control, and investments of greater than 50% in an investee over which the Company does not exercise significant influence or have control. Under the equity method of accounting, the Company’s share of the investee’s earnings or loss is recognized in the statement of operations. As of December 31, 2023, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one or two-month lag for its equity method investments.

Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other property and equipment was $1.4 millionshareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a non-controlling investment shall be accounted for using the cost method or the equity method.

The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such a loss has occurred, the Company recognizes an impairment provision. There were no significant impairments of the Company’s equity investments for the years ended December 31, 2017, 20162023, 2022 and 2015.2021. See Note 7—Equity Method Investments and Related Party Transactions for further details.


Investments in Real Estate

The Company has invested in certain real estate assets which are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life, and depreciation and amortization is calculated using the straight-line method over the assigned useful life.

Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

Investments in real estate, excluding insignificant unamortized in-place lease and above-market lease intangibles, consist of the following:
Estimated Useful LivesDecember 31,
20232022
(Years)(In millions)
Buildings20-30$98 $96 
Tenant improvements5 - 135 5 
LandN/A1 1 
Land improvements5 - 151 1 
Total real estate assets105 103 
Less: accumulated depreciation and amortization(23)(20)
Total investment in land and buildings, net$82 $83 

Asset Retirement Obligations


The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.


The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.



The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. For additional information regarding the Company’s asset retirement obligations, see Note 6—Asset Retirement Obligations.
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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Impairment of Long-Lived Assets


Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no suchsignificant impairment losses for the years ended December 31, 2017, 20162023, 2022 and 2015, respectively.2021.


Capitalized Interest


The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projectsunevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $22.1 millionSee Note 8—Debt for the year ended December 31, 2017. The Company did not have any capitalized interest for the years ended December 31, 2016 and 2015.further details.


Inventories


Inventories are stated at the lower of cost or marketnet realizable value and primarily consist of tubular goods and equipment at December 31, 20172023 and 2016.2022. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2017, the Company estimated that all of its tubular goods and equipment will be utilized within one year.


Debt Issuance Costs


Other assets included capitalized costs related to the credit facility of $16.7 million and $8.2 million, net of accumulated amortization of $7.0 million and $4.9 million, as of December 31, 2017 and 2016, respectively. Long-term debt includedincludes capitalized costs related to the senior notes, of $15.2 million and $14.8 million, net of accumulated amortization of $2.0 million and $0.2 million, as of December 31, 2017 and 2016, respectively.amortization. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior
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notes using the effective interest method. See Note 8—Debt for further details. The costs associated with the Company’s credit facility thatfacilities are included in other assets on the consolidated balance sheet and are being amortized over the term of the facility.


Other Accrued Liabilities


The Company’s accrued liabilities are financial instruments for which the carrying value approximates fair value.

Other accrued liabilities consist of the following:following at December 31, 2023, and 2022:
December 31,
20232022
(In millions)
Derivative liability payable$13 $21 
Lease operating expenses payable160 131 
Ad valorem taxes payable129 108 
Accrued compensation38 35 
Interest payable73 49 
Midstream operating expenses payable8 15 
Other54 40 
Total other accrued liabilities$475 $399 
 December 31,
 2017 2016
 (In thousands)
Liability for drilling costs prepaid by joint interest partners$30,320
 $21,595
Interest payable6,770
 5,445
Lease operating expenses payable27,850
 13,857
Ad valorem taxes payable3,306
 776
Current portion of asset retirement obligations1,163
 1,288
Other23,103
 12,369
Total other accrued liabilities$92,512
 $55,330


Revenue and Royalties Payable


For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.


Revenue RecognitionNon-controlling Interests


Oil and natural gas revenues are recorded when title passesNon-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper as well as Rattler prior to the purchaser, netRattler Merger, and are presented as a component of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded whenequity. When the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells whererelative ownership interests change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, occur. Because these changes in the Company has taken less than its ownership shareinterests do not result in a change of production. The Company did not have any gas imbalances as of December 31, 2017 or December 31, 2016. Revenues from oil and natural gas services are recognized when services are provided.

Investments

Equity investments in whichcontrol, the Company exercises significant influence but does not controltransactions are accounted for usingas equity transactions under ASC Topic 810, “Consolidation,” which requires that any differences between the equity method. Under the equity method, generallycarrying value of the Company’s sharebasis in Viper and Rattler prior to the Rattler Merger and the fair value of investees�� earnings or loss isthe consideration received are recognized directly in equity and attributed to the controlling interest. See Note 9—Stockholders' Equity and Earnings Per Share for a discussion of changes in the statement of operations. The Company reviews its investments to determine if a lossCompany’s ownership interest in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments forconsolidated subsidiaries during the years ended December 31, 2017, 20162023, 2022 and 2015.2021.


For additional informationRevenue Recognition

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deductions. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the
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Notes to Consolidated Financial Statements-(Continued)

delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s investments, seeconsolidated statements of operations.

Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. Generally, the midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Net sales of purchased oil

The Company enters into pipeline capacity commitments in order to secure available transportation capacity from the Company's areas of production for its commodities. Beginning in the third quarter of 2023, the Company has also entered into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of its unused oil pipeline capacity commitments. Revenues and expenses from these transactions are generally presented on a gross basis in the captions “Sales of purchased oil” and “Purchased oil expense” in the accompanying consolidated statements of operations as the Company acts as a principal in the transaction by assuming both the risks and rewards of ownership, including credit risk, of the oil volumes purchased and the responsibility to deliver the oil volumes sold.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts.
Under the Company’s revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the years ended
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Notes to Consolidated Financial Statements-(Continued)

December 31, 2023, 2022 and 2021 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

See Note 7–Equity Method Investments.3—Revenue from Contracts with Customers for additional discussion of the Company’s revenues.


Accounting for Equity-Based Compensation


The Company grantshas granted various types of stock-based awards including stock options and restricted stock units. The Partnership grantsViper and Rattler, prior to the Rattler Merger, have granted various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership.respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 10–10—Equity-Based Compensation.Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed net of estimated forfeitures, over the required service period. Forfeitures for these awards are recognized as they occur.


Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Environmental Compliance and Remediation


Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.


Income Taxes


DiamondbackThe Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. For additional information regarding income taxes, see Note 11—Income Taxes.


Accumulated Other Comprehensive Income (Loss)

The Company is subject to margin taxfollowing table provides changes in the statecomponents of Texas. During the years ended December 31, 2017, 2016accumulated other comprehensive income, net of related income tax effects related to insignificant pension and 2015,postretirement benefit plans the Company had no margin tax expense. The Company’s 2013, 2014, 2015, 2016acquired from Energen and 2017 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2017 and December 31, 2016, the Company had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2017, 2016 and 2015, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.QEP (in millions):


Year Ended December 31,
20232022
(In millions)
Balance at beginning of the period$(7)$— 
Net actuarial gain (loss) on pension and postretirement benefit plans(1)(9)
Income tax benefit (expense)— 2 
Balance at end of the period$(8)$(7)

Recent Accounting Pronouncements


Recently IssuedAdopted Pronouncements


In May 2014,October 2021, the FinancialFASB issued ASU 2021-08, “Business Combinations (Topic 805) – Accounting Standards Board issued Accounting Standards Update 2014-09,for Contract Assets and Contract Liabilities from Contracts with Customers.” This update required the acquirer in a business combination to record contract assets and liabilities following Topic 606 – “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when at acquisition as if it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.

The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that

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Notes to Consolidated Financial Statements-(Continued)



when substantially all ofhad originated the contract, rather than at fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business.value. The Company will adoptadopted this update prospectively effective January 1, 2018.2023. The adoption of this update willdid not have a material impact on the Company’s financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In March 2023, the FASB issued ASU 2023-01, “Leases (Topic 842) – Common Control Arrangements.” This update (i) requires all lessees that are a party to a lease between entities under common control in which there are leasehold improvements to record amortization utilizing the shorter period of the remaining lease term and the useful life of the improvements, and (ii) requires leasehold improvements to be accounted for as a transfer between entities under common control through an adjustment to equity if, and when, the lessee no longer controls the use of the underlying asset. This update is effective for fiscal years beginning after December 15, 2023 with early adoption permitted. The Company may adopt this update (i) prospectively to all new leasehold improvements on or after the date of adoption, (ii) prospectively to all new and existing leasehold improvements on or after the date of adoption, or (iii) retrospectively to the beginning of the period in which the Company first applied Topic 842. The Company continues to evaluate the provisions of this update but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted


In February 2016,November 2023, the Financial Accounting Standards BoardFASB issued Accounting Standards Update 2016-02, “Leases”. This update appliesASU 2023-07, “Segment Reporting (Topic 280) – Improvements to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liabilityReportable Segment Disclosures,” which updates reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and information used to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will beassess segment performance. The amendments are effective for public entitiesannual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2018, including interim2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods within those fiscal years, with early adoption permitted. Entities will be requiredpresented in the financial statements. Management is currently evaluating this ASU to recognize and measure leases atdetermine its impact on the beginningCompany's disclosures. Adoption of the earliest period presented using a modified retrospective approach. The Company believesupdate will not impact the primary impactCompany’s financial position, results of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.operations or liquidity.


In June 2016,December 2023, the Financial Accounting Standards BoardFASB issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assetsASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated, and net investment in leases that are not accounted for at fair value through net income.provides additional requirements regarding income taxes paid. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will beare effective for financial statements issued for fiscal yearsannual periods beginning after December 15, 2019, including interim periods within those fiscal years. This update will2024, with early adoption permitted, and should be applied through a cumulative-effect adjustmenteither prospectively or retrospectively. Management is currently evaluating this ASU to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a materialdetermine its impact on the Company’s consolidateddisclosures. Adoption of the update will not impact the Company’s financial statements sinceposition, results of operations or liquidity.

The Company considers the Company doesapplicability and impact of all ASUs. ASUs not have a history of credit losses.listed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.


3.    ACQUISITIONSREVENUE FROM CONTRACTS WITH CUSTOMERS
2017 Activity

Revenue from Contracts with Customers
On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.


The following representstables present the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.Company’s revenue from contracts with customers:

Year Ended December 31,
202320222021
(In millions)
Oil sales$7,279 $7,660 $5,396 
Natural gas sales262 858 569 
Natural gas liquid sales687 1,048 782 
Total oil, natural gas and natural gas liquid revenues8,228 9,566 6,747 
Sales of purchased oil111 — — 
Midstream and marketing services62 69 45 
Total revenue from contracts with customers$8,401 $9,635 $6,792 


81
 (in thousands)
Proved oil and natural gas properties$386,308
Unevaluated oil and natural gas properties2,122,597
Midstream assets47,432
Prepaid capital costs3,460
Oil inventory839
Equipment163
Revenues and royalties payable(9,650)
Asset retirement obligations(1,550)
Total fair value of net assets$2,549,599

The Company has included in its consolidated statements of operations revenues of $81.4 million and direct operating expenses of $23.5 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition.

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Notes to Consolidated Financial Statements-(Continued)




Pro Forma Financial Information

The following unaudited summary pro forma consolidated statementtables present the Company’s revenue from oil, natural gas, and natural gas liquids disaggregated by basin:

Year Ended December 31, 2023
Midland BasinDelaware BasinOtherTotal
(In millions)
Oil sales$5,746 $1,527 $6 $7,279 
Natural gas sales176 85 1 262 
Natural gas liquid sales500 187 — 687 
Total$6,422 $1,799 $7 $8,228 

Year Ended December 31, 2022
Midland BasinDelaware BasinOtherTotal
(In millions)
Oil sales$5,541 $2,107 $12 $7,660 
Natural gas sales563 292 3 858 
Natural gas liquid sales719 327 2 1,048 
Total$6,823 $2,726 $17 $9,566 

Year Ended December 31, 2021
Midland BasinDelaware BasinOtherTotal
(In millions)
Oil sales$3,468 $1,663 $265 $5,396 
Natural gas sales327 215 27 569 
Natural gas liquid sales493 249 40 782 
Total$4,288 $2,127 $332 $6,747 

Customers

The Company is subject to risk resulting from the concentration of operations data of Diamondback forits crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 20172023, four purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (22%), DK Trading & Supply LLC (18%), Shell Trading (USA) Company (“Shell”) (14%) and 2016 have been prepared to give effect toEnterprise Crude Oil LLC (13%). For the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicativeyear ended December 31, 2022, two purchasers each accounted for more than 10% of the financial results that would have been attained hadCompany’s revenue: Vitol (23%) and Shell (20%). For the acquisitions occurred on January 1, 2016.

The pro forma data also necessarily exclude various operation expenses related toyear ended December 31, 2021, three purchasers each accounted for more than 10% of the propertiesCompany’s revenue: Vitol (21%); Shell (19%); and the financial statements should not be viewed as indicative of operations in future periods.
 Year Ended December 31,
 2017 2016
 (in thousands, except per share amounts)
Revenues$1,228,040
 $627,301
Income (loss) from operations619,369
 (12,812)
Net income (loss)472,649
 (109,229)
Basic earnings per common share4.85
 (1.45)
Diluted earnings per common share4.84
 (1.45)

2016 Activity

On September 1, 2016, the Company acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties.Plains Marketing, L.P. (12%). The Company financed this acquisition with net proceeds fromdoes not require collateral and does not believe the July 2016 equity offering discussed in Note 9 and cash on hand.

2015 Activity

During 2015, the Company completed acquisitions from unrelated third party sellersloss of an aggregate of approximately 16,940 gross (12,672 net) acres in the Midland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9–Capital Stock and Earnings Per Share and borrowings under the Company’s revolving credit facility discussed in Note 8–Debt.

On July 9, 2015, the Company completed the sale of an approximate average 1.5% overriding royalty interest in certain ofany single purchaser would materially impact its acreage primarily located in Howard County, Texas to the Partnership for $31.1 million. The Partnership primarily funded this acquisition with borrowings under its revolving credit facility discussed in Note 8 – Debt.

4.    VIPER ENERGY PARTNERS LP

The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploitoperating results, as crude oil and natural gas properties in North America. The Partnership is currently focused on oilare fungible products with well-established markets and natural gas properties in the Permian Basin.numerous purchasers.

4.    ACQUISITIONS AND DIVESTITURES

2023 Activity

Acquisitions

GRP Acquisition

On November 1, 2023, Viper and Viper LLC acquired certain mineral and royalty interests from Royalty Asset Holdings, LP, Royalty Asset Holdings II, LP and Saxum Asset Holdings, LP and affiliates of Warwick Capital Partners and GRP Energy Partners GP LLC,Capital (collectively, “GRP”), pursuant to a consolidated subsidiary of Diamondback, serves as the general partner of,definitive purchase and holds a non-economic general partner interest in, the Partnership. As of December 31, 2017, the Company ownedsale agreement for approximately 64% of the9.02 million Viper common units of the Partnership.

Priorand $760 million in cash, including transaction costs and subject to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit. In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a

customary post-closing
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Notes to Consolidated Financial Statements-(Continued)



adjustments (the “GRP Acquisition”). The mineral and royalty interests acquired in the GRP Acquisition represent 4,600 net royalty acres in the Permian Basin, plus an additional 2,700 net royalty acres in other major basins. The cash consideration for the GRP Acquisition was funded through a combination of entitiescash on hand and held in escrow, borrowings under the Viper credit agreement, proceeds from the Viper 2031 Notes (as defined in Note 8—Debt) and proceeds from the $200 million common controlunit issuance to the Company.

Deep Blue Formation and Divestiture of Deep Blue Water Assets

On September 1, 2023, the Company closed on a joint venture agreement with Five Point Energy LLC (“Five Point”) to form Deep Blue Midland Basin LLC (“Deep Blue”). At closing, the Company contributed certain treated water, fresh water and saltwater disposal assets (the “Deep Blue Water Assets”) with a net carrying value of $692 million and liabilities transferredFive Point contributed $251 million in cash, subject to certain customary post-closing adjustments, to Deep Blue. In exchange for these contributions, Deep Blue issued the Company a one-time cash distribution of approximately $516 million and issued to the Company a 30% equity ownership and voting interest, and issued to Five Point a 70% equity ownership and voting interest.

Under a separate agreement with Deep Blue, the Company is continuing to operate the Deep Blue Water Assets on a short-term basis before transferring operations to Deep Blue, which is anticipated to happen in 2024. Contingent upon the successful transfer of operations, the Company will receive approximately $47 million in cash to be contributed by Five Point in 2024. This contingent consideration does not meet the criteria to be accounted for as a derivative. As such, at their carrying amountsDecember 31, 2023, approximately $43 million has been recorded as a receivable in the consolidated balance sheet for the fair value of the additional consideration to be received when operation of the Deep Blue Water Assets transfers to Deep Blue.

The Company recorded its 30% equity interest in Deep Blue at fair value based on the cash consideration contributed by Five Point to Deep Blue in exchange for its 70% equity ownership and the estimated fair value of contingent consideration to be contributed by Five Point in future years. The Company’s equity method investment in Deep Blue had an initial fair value of $126 million. The Company’s proportionate share of the income or loss from Deep Blue will be recognized on a manner similar to a pooling of interests.

Duringtwo-month lag. For the year ended December 31, 2017,2023, the Partnership distributed $89.5Company recognized a $12 million to Diamondback in respectloss on the sale of its common units.

In August 2016, the Partnership completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, Diamondback purchased 2,000,000 common units from the underwriter at $15.60 per unit,Deep Blue Water Assets, which is included in the price per common unit paid bycaption “Other operating expenses” in the underwriterconsolidated statement of operations. The majority of measurements utilized to determine the Partnership. Followingfair value amounts reported above relating to this transaction are based on inputs that are not observable in the August 2016 public offering, Diamondback had an approximate 83% limited partnermarket and are therefore considered Level 3 inputs in the fair value hierarchy.

The Company and Five Point currently anticipate collectively contributing $500 million in follow-on capital to fund future growth projects and acquisitions.

As part of the transaction, the Company also entered into a 15-year dedication with Deep Blue for its produced water and supply water within a 12-county area of mutual interest in the Partnership. The PartnershipMidland Basin. Fees paid to Deep Blue for produced water and supply water services and fees received net proceeds from this offering of approximately $125.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which it used to fund an acquisition and repaid outstanding borrowings under its revolving credit facility.
In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was usedDeep Blue for general partnership purposes, which included additional acquisitions.
In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors ofoperating services provided by the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, the Company had an approximate 64% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used fund a portion of the purchase price for acquisitions and for general partnership purposes.
As a result of these public offerings and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in the Partnership was reduced. Duringduring the year ended December 31, 2017,2023 were insignificant.

Lario Acquisition

On January 31, 2023, the Company recordedclosed on its acquisition of all leasehold interests and related assets of Lario Permian, LLC, a $362.4 million decrease to Non-controlling interestwholly owned subsidiary of Lario Oil and Gas Company, and certain associated sellers (collectively “Lario”). The acquisition included approximately 25,000 gross (16,000 net) acres in the Partnership with an increase to Additional paid-in capital, which represents the difference betweenMidland Basin and certain related oil and gas assets (the “Lario Acquisition”), in exchange for 4.33 million shares of the Company’s sharecommon stock and $814 million in cash, including certain customary post-closing adjustments. Approximately $113 million of the underlying net book valuecash consideration was deposited in the Partnership before and after the respective Partnership common unit transactions,an indemnity holdback escrow account at closing to be distributed upon satisfactory settlement of any potential title defects on the Company’s consolidated balance sheet.

Partnership Agreement

In connection with the closingacquired properties. The cash portion of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform servicesconsideration for the Partnership orLario Acquisition was funded through a combination of cash on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership.

Tax Sharing

In connection with the closinghand, a portion of the Viper Offering,net proceeds from the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to whichCompany’s offering of 6.250% Senior Notes due 2053 and borrowings under the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed hadCompany’s revolving credit facility.


F-15
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The following table presents the acquisition consideration paid in the Lario Acquisition (in millions, except per share data, shares in thousands):

Consideration:
Shares of Diamondback common stock issued at closing4,330
Closing price per share of Diamondback common stock on the closing date$146.12 
Fair value of Diamondback common stock issued$633 
Cash consideration814 
Total consideration (including fair value of Diamondback common stock issued)$1,447 

Purchase Price Allocation

The Lario Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Lario Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The purchase price allocation was completed in December 2023, with no further adjustments to the previously reported fair values of assets acquired and liabilities assumed.

The following table sets forth the Company’s purchase price allocation (in millions):

Total consideration$1,447 
Fair value of liabilities assumed:
Other long-term liabilities37 
Fair value of assets acquired:
Oil and natural gas properties1,460 
Inventories2 
Other property, equipment and land22 
Amount attributable to assets acquired1,484 
Net assets acquired and liabilities assumed$1,447 

Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets, vehicles and a field office were based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets and were included in the Company’s consolidated balance sheets under the caption “Other property, equipment and land.” The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs in the fair value hierarchy.

With the completion of the Lario Acquisition, the Company acquired proved properties of $924 million and unproved properties of $536 million. The results of operations attributable to the Lario Acquisition since the acquisition date have been included in the consolidated statements of operations and include $488 million of total revenue and $200 million of net income for the year ended December 31, 2023.

Divestitures

OMOG Divestiture

On July 28, 2023, the Company divested its 43% limited liability company interest in OMOG JV LLC (“OMOG”) for $225 million in cash received at closing. This divestiture resulted in a gain on the sale of equity method investments of approximately $35 million for the year ended December 31, 2023, which is included in the caption “Other income (expense), net” in the consolidated statement of operations. The Company used its net proceeds from this transaction for debt reduction and other general corporate purposes.

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Non-Core Assets Divestitures

On April 28, 2023, the Company divested non-core assets to an unrelated third-party buyer consisting of approximately 19,000 net acres in Glasscock County, TX for net cash proceeds at closing of $269 million, including customary post-closing adjustments. The Company used its net proceeds from this transaction for debt reduction and other general corporate purposes.

On March 31, 2023, the Company divested non-core assets consisting of approximately 4,900 net acres in Ward and Winkler counties to unrelated third-party buyers for $72 million in net cash proceeds, including customary post-closing adjustments.

The divestitures of non-core oil and gas assets did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale.

Gray Oak Divestiture

On January 9, 2023, the Company divested its 10% non-operating equity investment in Gray Oak Pipeline, LLC (“Gray Oak”) for $172 million in net cash proceeds and recorded a gain on the sale of equity method investments of approximately $53 million in the first quarter of 2023 that is included in the caption “Other income (expense), net” on the consolidated statement of operations for the year ended December 31, 2023.

2022 Activity

Acquisitions

FireBird Energy LLC Acquisition

On November 30, 2022, the Company closed on its acquisition of all leasehold interests and related assets of FireBird Energy LLC, which included approximately 75,000 gross (68,000 net) acres in the Midland Basin and certain related oil and gas assets, in exchange for 5.92 million shares of the Company’s common stock and $787 million in cash, including certain customary post-closing adjustments. Approximately $125 million of the cash consideration was deposited in an indemnity holdback escrow account at closing to be distributed upon satisfactory settlement of any potential title defects on the acquired properties. The cash portion of the consideration for the FireBird Acquisition was funded through a combination of cash on hand and borrowings under the Company’s revolving credit facility. As a result of the FireBird Acquisition, the Company added approximately 854 gross producing wells.

The following table presents the acquisition consideration paid in the FireBird Acquisition (in millions, except per share data, shares in thousands):

Consideration:
Shares of Diamondback common stock issued at closing5,921
Closing price per share of Diamondback common stock on the closing date$148.02 
Fair value of Diamondback common stock issued$876 
Cash consideration787 
Total consideration (including fair value of Diamondback common stock issued)$1,663 

Purchase Price Allocation

The FireBird Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the FireBird Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The purchase price allocation was completed during November 2023 with no further adjustments to the previously reported fair values of assets acquired and liabilities assumed.


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The following table sets forth the Company’s purchase price allocation (in millions):

Total consideration$1,663 
Fair value of liabilities assumed:
Other long-term liabilities10 
Fair value of assets acquired:
Oil and natural gas properties1,598 
Inventories3 
Other property, equipment and land72 
Amount attributable to assets acquired1,673 
Net assets acquired and liabilities assumed$1,663 

Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets and was included in the Company’s consolidated balance sheets under the caption “Other property, equipment and land.” The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs.

With the completion of the FireBird Acquisition, the Company acquired proved properties of $648 million and unproved properties of $950 million. The results of operations attributable to the FireBird Acquisition from the acquisition date through December 31, 2022 have been included in the consolidated statement of operations and include $46 million of total revenue and $28 million of net income.

Delaware Basin Acquisition

On January 18, 2022, the Company acquired, from an unrelated third-party seller, approximately 6,200 net acres in the Delaware Basin for $232 million in cash, including customary post-closing adjustments. The acquisition was funded through cash on hand.

Other 2022 Acquisitions

Additionally during the year ended December 31, 2022, the Company acquired, from unrelated third-party sellers, approximately 4,000 net acres and over 200 gross wells in the Permian Basin for an aggregate purchase price of approximately $220 million in cash, including customary closing adjustments. The acquisitions were funded through cash on hand.

Divestitures

Non-Core Assets Divestitures

In October 2022, the Company completed the divestiture of non-core Delaware Basin acreage consisting of approximately 3,272 net acres, with net production of approximately 550 BO/d (800 BOE/d) for $155 million of net proceeds. The Company used the net proceeds from this transaction towards debt reduction.


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2021 Activity

Acquisitions

Guidon Operating LLC

On February 26, 2021, the Company closed on its acquisition of all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”), which included approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The cash portion of the consideration for the Guidon Acquisition was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells.

The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands):

Consideration:
Shares of Diamondback common stock issued at closing10,676
Closing price per share of Diamondback common stock on the closing date$69.28 
Fair value of Diamondback common stock issued$740 
Cash consideration375 
Total consideration (including fair value of Diamondback common stock issued)$1,115 

Purchase Price Allocation

The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The purchase price allocation was completed in the first quarter of 2022.

The following table sets forth the Company’s purchase price allocation (in millions):

Total consideration$1,115 
Fair value of liabilities assumed:
Asset retirement obligations9 
Fair value of assets acquired:
Oil and natural gas properties1,110 
Midstream assets14
Amount attributable to assets acquired1,124 
Net assets acquired and liabilities assumed$1,115 

Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs.

With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition from the acquisition date through December 31, 2021 have been included in the consolidated statements of operations for the year ended December 31, 2021, and include $345 million of total revenue and $170 million of net income.
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QEP Resources, Inc.

On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion.

The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands):

Consideration:
Eligible shares of QEP common stock converted into shares of Diamondback common stock238,153 
Shares of QEP equity awards included in precombination consideration4,221 
Total shares of QEP common stock eligible for merger consideration242,374 
Exchange ratio0.050 
Shares of Diamondback common stock issued as merger consideration12,119 
Closing price per share of Diamondback common stock$81.41 
Total consideration (fair value of the Company's common stock issued)$987 

Purchase Price Allocation

The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities at the acquisition date. The purchase price allocation was completed in the first quarter of 2022.

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The following table sets forth the Company’s purchase price allocation (in millions):

Total consideration$987 
Fair value of liabilities assumed:
Accounts payable - trade$26 
Accrued capital expenditures38 
Other accrued liabilities107 
Revenues and royalties payable67 
Derivative instruments242 
Long-term debt1,710 
Asset retirement obligations54 
Other long-term liabilities63 
Amount attributable to liabilities assumed$2,307 
Fair value of assets acquired:
Cash, cash equivalents and restricted cash$22 
Accounts receivable - joint interest and other, net87 
Accounts receivable - oil and natural gas sales, net44 
Inventories18 
Income tax receivable33 
Prepaid expenses and other current assets7 
Oil and natural gas properties2,922 
Other property, equipment and land16 
Deferred income taxes39 
Other assets106 
Amount attributable to assets acquired3,294 
Net assets acquired and liabilities assumed$987 

The purchase price allocation above was based on estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity price curves which are considered Level 2 inputs. Deferred income taxes represent the tax attributes noteffects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed.

With the completion of the QEP Merger, the Company acquired proved properties of $2.0 billion and unproved properties of $733 million, primarily in the Midland Basin and the Williston Basin. In October 2021, the Company completed the divestiture of the Williston Basin properties, acquired as part of the QEP Merger and consisting of approximately 95,000 net acres, to Oasis Petroleum Inc. for net cash proceeds of approximately $586 million, after customary closing adjustments. See “—Williston Basin Divestiture” below.

The results of operations attributable to the QEP Merger since the acquisition date have been available or usedincluded in the consolidated statements of operations and include $1.1 billion of total revenue and $455 million of net income for the Partnership’s benefit, even though year ended December 31, 2021.

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Viper’s Swallowtail Acquisition

On October 1, 2021, Viper acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition had noan effective date of August 1, 2021. The cash tax expenseportion of the consideration for that period.

Other Agreements

See Note 11–Related Party Transactions for information regarding the advisory services agreement the PartnershipSwallowtail Acquisition was funded through a combination of Viper’s cash on hand and the General Partner entered into with Wexford Capital LP (“Wexford”).

The Partnership has entered into a securedapproximately $190 million of borrowings under Viper LLC’s revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 8–Debt for a description of this credit facility.


Rattler’s WTG Joint Venture Acquisition

On October 5, 2021, Rattler and a private affiliate of an investment fund formed the WTG joint venture. Rattler contributed approximately $104 million in cash for a 25% membership interest in the WTG joint venture, which then completed the acquisition of a majority interest in WTG Midstream from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.

Divestitures

On June 3, 2021 and June 7, 2021, respectively, the Company closed transactions to divest certain non-core Permian assets including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for combined net cash proceeds of $82 million, after customary closing adjustments. The Company used its net proceeds from these transactions toward debt reduction.

Williston Basin Divestiture

On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction.

Gas Gathering Assets Divestiture

On November 1, 2021, the Company completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream (“Brazos”), for net cash proceeds of approximately $54 million, after customary closing adjustments.

2021 Drop Down Transaction

On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $164 million, in a drop down transaction (the “Drop Down”). The midstream assets consisted primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $164 million. The Company and Rattler also mutually amended their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control.

Rattler’s Gas Gathering Divestiture

On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for aggregate total consideration of $84 million, after customary closing adjustments.

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Pro Forma Financial Information (Unaudited)

The following unaudited summary pro forma financial information for the years ended December 31, 2023, 2022 and 2021 has been prepared to give effect to (i) the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020, (ii) the FireBird Acquisition as if it had occurred on January 1, 2021, and (iii) the Lario Acquisition as if it had occurred on January 1, 2022. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company.

The below information reflects pro forma adjustments for the issuance of the Company’s common stock as consideration for Firebird, Lario and QEP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of (i) $8 million and $3 million for the Lario Acquisition and the FireBird Acquisition during the year ended December 31, 2023, respectively, (ii) $2 million for the FireBird Acquisition during the year ended December 31, 2022, (iii) $78 million for the QEP Merger and the Guidon Acquisition during the year ended December 31, 2021, and (iv) $31 million of costs incurred by QEP through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger, the Guidon Acquisition, the FireBird Acquisition and the Lario Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

Year Ended December 31,
202320222021
(In millions, except per share amounts)
Revenues$8,457 $10,542 $7,198 
Income (loss) from operations$4,607 $7,071 $4,193 
Net income (loss)$3,175 $4,834 $2,148 
Basic earnings per common share$17.48 $25.74 $11.40 
Diluted earnings per common share$17.48 $25.74 $11.40 
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5.    PROPERTY AND EQUIPMENT


Property and equipment includes the following:
December 31,
20232022
(In millions)
Oil and natural gas properties:
Subject to depletion$33,771 $28,767 
Not subject to depletion8,659 8,355 
Gross oil and natural gas properties42,430 37,122 
Accumulated depletion(8,333)(6,671)
Accumulated impairment(7,954)(7,954)
Oil and natural gas properties, net26,143 22,497 
Other property, equipment and land673 1,481 
Accumulated depreciation, amortization, accretion and impairment(142)(219)
Total property and equipment, net$26,674 $23,759 
Balance of costs not subject to depletion:
Incurred in 2023$1,470 
Incurred in 2022827 
Incurred in 20211,136 
Prior5,226 
Total not subject to depletion$8,659 
 December 31,
 2017 2016
 (in thousands)
Oil and natural gas properties:   
Subject to depletion$5,126,829
 $3,429,742
Not subject to depletion4,105,865
 1,730,519
Gross oil and natural gas properties9,232,694
 5,160,261
Accumulated depletion(1,009,893) (687,685)
Accumulated impairment(1,143,498) (1,143,498)
Oil and natural gas properties, net7,079,303
 3,329,078
Midstream assets191,519
 8,362
Other property, equipment and land80,776
 58,290
Accumulated depreciation(7,981) (4,873)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$7,343,617
 $3,390,857
    
Balance of costs not subject to depletion:   
Incurred in 2017$2,746,936
  
Incurred in 2016727,411
  
Incurred in 2015301,879
  
Incurred in 2014316,455
  
Incurred in 201313,184
  
Total not subject to depletion$4,105,865
  

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $22.0$66 million, $17.2$58 million and $15.2$60 million for the years ended December 31, 2017, 20162023, 2022 and 2015,2021, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion ofAlthough the Company’sevaluation process has not been completed on our unevaluated properties, the Company currently estimates these costs intowill be added to the amortization base is expected to be completed within three to fiveten years. Acquisition costs not currently being amortized are primarily related to unproved acreage that

Under the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as

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Notes to Consolidated Financial Statements-(Continued)


adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under thisfull cost method of accounting, the Company is required to perform a ceiling test each quarter. The testquarter which determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligationsNo impairment expense was recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

As a result of the significant decline in prices during 2016, the Company recorded non-cash ceiling test impairments for the years ended December 31, 20162023, 2022 and 2015 of $245.5 million and $814.8 million, respectively, which are included in accumulated depletion. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. For 2016 and 2015, the impairment charges affected the Company’s reported net income but did not reduce its cash flow. 2021.

In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. Given the rate of change impacting the oil and natural gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.


In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there was not a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.

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At December 31, 2017,2023, there was $26.0were $77 million in exploration costs and development costs and $22.1$337 million in capitalized interest that are not subject to depletion. At December 31, 2016,2022, there were no$126 million in exploration costs,and development costs orand $206 million in capitalized interest costs that arewere not subject to depletion.


6.    ASSET RETIREMENT OBLIGATIONS


The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
Year Ended December 31,
20232022
(In millions)
Asset retirement obligations, beginning of period$347 $171 
Additional liabilities incurred4 36 
Liabilities acquired8 19 
Liabilities settled and divested(88)(26)
Accretion expense16 14 
Revisions in estimated liabilities(1)
(42)133 
Asset retirement obligations, end of period245 347 
Less: current portion(2)
6 11 
Asset retirement obligations - long-term$239 $336 
 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Asset retirement obligations, beginning of period$17,422
 $12,711
 $8,486
Additional liabilities incurred1,526
 637
 594
Liabilities acquired2,432
 3,696
 3,159
Liabilities settled(1,555) (711) (292)
Accretion expense1,391
 1,064
 833
Revisions in estimated liabilities69
 25
 (69)
Asset retirement obligations, end of period21,285
 17,422
 12,711
Less current portion1,163
 1,288
 193
Asset retirement obligations - long-term$20,122
 $16,134
 $12,518
(1) Revisions in estimated liabilities for the year ended December 31, 2023 are primarily the result of changes in estimated future plugging and abandonment costs due to reductions in current cost estimates and other factors.

(2) The current portion of the asset retirement obligation is included in the caption “Other accrued liabilities” in the Company’s consolidated balance sheets.

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.


7.    EQUITY METHOD INVESTMENTS AND RELATED PARTY TRANSACTIONS


In October 2014,The Company considers its equity method investees to be related parties. At December 31, 2023 and 2022, the Company obtained a 25% interesthad the following significant equity method investments:
Ownership InterestDecember 31, 2023December 31, 2022
(In millions)
EPIC Crude Holdings, LP10 %$93 $101 
Gray Oak Pipeline, LLC(1)(2)
— %— 115 
Wink to Webster Pipeline LLC4 %92 87 
OMOG JV LLC(2)
— %— 191 
BANGL LLC10 %29 28 
WTG joint venture25 %182 156 
Deep Blue Midland Basin LLC30 %128 — 
Othervarious5 3 
Total$529 $681 
(1) The Company’s investment of $115 million in HMW Fluid Management LLC, whichGray Oak was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operatingclassified in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other countiesassets held for sale in the Permian Basinconsolidated balance sheet at December 31, 2022, and to pursue other business opportunities.was subsequently divested in January 2023 as further discussed in Note 4—Acquisitions and Divestitures.

(2) The Company’s investment of $190 million in OMOG was divested in July 2023 as further discussed in Note 4—Acquisitions and Divestitures.

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Currently, the Company receives distributions from Wink to Webster and prior to their divestitures, received distributions from Gray Oak and OMOG, which are classified either within the operating or investing sections of the consolidated statements of cash flows by determining the nature of each distribution. The following table presents total distributions received from the Company’s equity method investments for the periods indicated:
During
Year Ended December 31,
202320222021
(In millions)
Gray Oak Pipeline, LLC$— $28 $26 
Wink to Webster Pipeline LLC13 5 — 
OMOG JV LLC23 19 18 
Total$36 $52 $44 

The following summarizes the yearincome (loss) of equity method investees for the periods presented:

Year Ended December 31,
202320222021
(In millions)
EPIC Crude Holdings, LP$(8)$(7)$(16)
Gray Oak Pipeline, LLC3 22 16 
Wink to Webster Pipeline LLC9 4 (3)
OMOG JV LLC17 14 12 
WTG joint venture26 44 6 
Deep Blue Midland Basin LLC2 — — 
Other(1)— — 
Total$48 $77 $15 

The Company reviews its equity method investments to determine if a loss in value which is other than temporary has occurred when events indicate the carrying value of the investment may not be recoverable. If such a loss has occurred, the Company recognizes an impairment provision. No significant impairments were recorded for the Company’s equity method investments for the years ended December 31, 2017,2023, 2022 or 2021. If economic challenges occur in future periods, it could result in circumstances requiring the Company invested $0.2 million in this entity and recorded income of $0.7 million, which wasto record potentially material impairment charges on its equity method investments.

In addition to the Company’s share of HMW Fluid Management LLC’s net income, bringing the Company’s total investment to $7.2 millionequity method investments noted above, at December 31, 2017. During the year ended December 31, 2016,2023, the Company invested $2.3 millionalso has an insignificant investment in the Class A common stock of Verde Clean Fuels, Inc. The Company elected the fair value option for measuring the fair value of this entity and recorded income of $0.7 million,equity investment as discussed further in Note 13— Fair Value Measurements.

Related Party Transactions- Deep Blue

In addition to the equity method investee activity reported above, the Company had other significant related party transactions with Deep Blue which was the Company’s share of HMW Fluid Management LLC’s net income, bringing its total investment to $6.3 million at December 31, 2016. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company2023, include (i) contingent consideration and maintains a specific ownership account for each investor, similarother post-close adjustments receivable from Deep Blue, (ii) accrued capital expenditures and other accrued payables related to a partnershipcommitment to fund certain capital account structure. The Company accounts for this investment underexpenditures on projects that were in process at the equity method of accounting.

8.    DEBT
Long-term debt consistedtime of the following asDeep Blue transaction, and (iii) lease operating expenses and capitalized expenses related to fees paid to Deep Blue under a 15-year dedication for its produced water and supply water within a 12-county area of mutual interest in the dates indicated:Midland Basin.

94
 December 31,
 2017 2016
 (in thousands)
4.750 % Senior Notes due 2024500,000
 500,000
5.375 % Senior Notes due 2025500,000
 500,000
Unamortized debt issuance costs(13,153) (14,588)
Revolving credit facility397,000
 —
Partnership revolving credit facility93,500
 120,500
Total long-term debt$1,477,347
 $1,105,912

2024 Senior Notes

On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes, provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. See also “Note 16. Subsequent Events–New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.”

The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the 2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.


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Notes to Consolidated Financial Statements-(Continued)



The following table presents the significant related party balances included in the consolidated balance sheet at December 31, 2023:
2025 Senior Notes
December 31, 2023
(In millions)
Current assets - Accounts receivable$61 
Current liabilities - Accrued capital expenditures$(21)
Current liabilities - Other accrued liabilities$(18)


OnDuring the year ended December 20, 2016,31, 2023, the Company issued $500.0also paid Deep Blue approximately $35 million for water services provided during the completion phase of wells. These costs were capitalized and are included in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.
The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oilcaption “Oil and natural gas business and designate certain ofproperties” on the Company’s subsidiaries as unrestricted subsidiaries.consolidated balance sheet.

The Company may on any one or more occasions redeem some or allfollowing table presents the significant related party transactions included in the consolidated statement of the 2025 Senior Notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031%operations for the 12-month period beginning on Mayyear ended December 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes at a price equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.2023:

Year Ended December 31, 2023
(In millions)
Lease operating expenses$33 
Net income (loss)$(33)
As required under the terms of the registration rights agreements relating to the 2024 Senior Notes and the 2025 Senior Notes, on April 26, 2017, the Company filed with the SEC a Registration Statement on Form S-4 (the “Registration Statement”) relating to the exchange offers of the 2024 Senior Notes and the 2025 Senior Notes for substantially identical notes registered under the Securities Act (the “Exchange Offers”). The Registration Statement was declared effective by the SEC on June 21, 2017 and the Exchange Offers closed on July 27, 2017, in which all of the privately placed 2024 Senior Notes and 2025 Senior Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.

8.    DEBT
The Company’s Credit Facilitydebt consisted of the following as of the dates indicated:

December 31,
20232022
(In millions)
5.250% Senior Notes due 2023$— $10 
3.250% Senior Notes due 2026750 780 
5.625% Senior Notes due 2026(1)
14 14 
7.125% Medium-term Notes, Series B, due 202873 73 
3.500% Senior Notes due 2029921 1,021 
3.125% Senior Notes due 2031789 789 
6.250% Senior Notes due 20331,100 1,100 
4.400% Senior Notes due 2051650 650 
4.250% Senior Notes due 2052750 750 
6.250% Senior Notes due 2053650 650 
Unamortized debt issuance costs(46)(43)
Unamortized discount costs(23)(26)
Unamortized premium costs4 4 
Unamortized basis adjustment of dedesignated interest rate swap agreements(2)
(84)(106)
Viper revolving credit facility263 152 
Viper 5.375% Senior Notes due 2027430 430 
Viper 7.375% Senior Notes due 2031400 — 
Total debt, net6,641 6,248 
Less: current maturities of long-term debt— 10 
Total long-term debt$6,641 $6,238 
The(1) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and Diamondback O&G LLC, as borrower, entered intoremained the second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014, November 13, 2014, June 21, 2016, December 15, 2016 and November 28, 2017, with a syndicateissuer of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to two additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, the Company had elected a commitment amount of $1.0 billion and the Company had $397.0 million of outstanding borrowings under the revolving credit facility. See “Note 16. Subsequent Events-New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.”


these senior notes.
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(2)    Represents the unamortized basis adjustment related to two receive-fixed, pay variable interest rate swap agreements which were previously designated as fair value hedges of the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. These swaps were dedesignated in the second quarter of 2022 as discussed further in Note 12—Derivatives.

Debt maturities as of December 31, 2023, excluding debt issuance costs, premiums and discounts and the unamortized basis adjustment of dedesignated interest rate swap agreements are as follows:

Year Ending December 31,
(In millions)
2024$— 
2025— 
2026764 
2027430 
2028336 
Thereafter5,260 
Total$6,790 

References in this section to the Company shall mean Diamondback O&G LLC is the borrower under theEnergy, Inc. and Diamondback E&P, collectively, unless otherwise specified.

Second Amended and Restated Credit Facility

The Company maintains a credit agreement.agreement, as amended, which provides for a maximum credit amount of $1.6 billion, which may be further increased to a total maximum commitment of $2.6 billion. As of December 31, 2017,2023, the Company had no outstanding borrowings under the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s$1.6 billion available for future subsidiaries that are classified as restricted subsidiariesborrowings. The weighted average interest rate on borrowings under the credit agreement. Theagreement was 6.31%, 3.91% and 1.67% for the years ended December 31, 2023, 2022 and 2021, respectively. During the second quarter of 2023, the Company exercised an election to extend the maturity date of the credit agreement is also secured by substantially all ofone year to June 2, 2028, which may be further extended by one one-year extension pursuant to the assets ofterms set forth in the Company, Diamondback O&G LLC and the guarantors.credit agreement.
The outstanding
Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the CompanyDiamondback E&P that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%0.50%, and 3-month LIBOR1-month Adjusted Term SOFR plus 1.0%), in each case plus the applicable margin. After giving effect to the amendment, (i) the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on the Company’s long-term senior unsecured debt ratings.

The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65%. As of December 31, 2023, the Company was in compliance with all financial maintenance covenants under the revolving credit facility, as then in effect.

2023 Issuance of Notes

Viper 2031 Notes

On October 19, 2023, Viper completed an offering of $400 million in aggregate principal amount of its 7.375% Senior Notes maturing on November 1, 2031 (the “Viper 2031 Notes”). Viper received net proceeds of approximately $394 million, after deducting the initial purchasers’ discount and transaction costs, from the Viper 2031 Notes. Viper loaned the gross proceeds to Viper LLC, which used the proceeds to partially fund the cash portion of the GRP Acquisition.

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2023 Retirement of Notes

In the second quarter of 2023, the Company repurchased principal amounts of $30 million of its 3.250% Senior Notes due 2026 and $100 million of its 3.500% Senior Notes due 2029 for total cash consideration, including accrued interest paid, of $124 million. These repurchases resulted in an immaterial loss on extinguishment of debt during the year ended December 31, 2023.

The Company redeemed the principal amount of its $10 million 5.250% Senior Notes due 2023 at maturity on May 1, 2023.

2022 Issuance of Notes

2053 Notes Offering

On December 13, 2022, the Company issued $650 million aggregate principal amount of 6.250% Senior Notes due March 15, 2053 (the “2053 Notes”) and received net proceeds of $643 million, after deducting debt issuance costs and discounts of $7 million and underwriting discounts and offering expenses. Interest on the 2053 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on March 15, 2023.

2033 Notes Offering

On October 28, 2022, the Company issued $1.1 billion of 6.250% Senior Notes due March 15, 2033 (the “2033 Notes”) and received net proceeds of $1.1 billion, after deducting debt issuance costs and discounts of $15 million and underwriting discounts and offering expense. Interest on the 2033 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on March 15, 2023.

2052 Notes Offering

On March 17, 2022, the Company issued $750 million aggregate principal amount of 4.250% Senior Notes due March 15, 2052 (the “2052 Notes”) and received net proceeds of $739 million, after deducting debt issuance costs and discounts of $11 million and underwriting discounts and offering expenses. Interest on the 2052 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2022.

2022 Retirement of Notes

In the third quarter of 2022, the Company fully redeemed the $25 million principal amount of the outstanding 5.375% Notes due 2022 and fully repaid at maturity the $20 million principal amount of the outstanding 7.320% Medium-term Notes, Series A due 2022. The Company funded these transactions with cash on hand.

Additionally, the Company used a portion of the net proceeds from the 2033 Notes offering to fund, in full, the redemption of the $500 million principal amount of Rattler’s 5.625% Senior Notes due 2025. The redemption included a premium and accrued and unpaid interest for a total cash consideration of $522 million. These redemptions resulted in an immaterial loss on extinguishment of debt.

In the second quarter of 2022, the Company repurchased principal amounts of $27 million of its 7.125% Medium-term Notes due 2028, $111 million of its 3.125% Senior Notes due 2031, $179 million of its 3.500% Senior Notes due 2029 and $20 million of its 3.250% Senior Notes due 2026 for total cash consideration, including accrued interest of $322 million.

Additionally, during the second quarter of 2022, Viper repurchased $50 million in principal amount of its 5.375% Senior Notes due 2027 for total cash consideration of $49 million. These repurchases resulted in an immaterial loss on extinguishment of debt. The Company funded its repurchases with cash on hand and Viper funded its repurchases with cash on hand and borrowings under the Viper credit agreement.

In the first quarter of 2022, the Company fully redeemed the $500 million and $1.0 billion principal amounts of its outstanding 4.750% Senior Notes due 2025 and 2.875% Senior Notes due 2024, respectively. Cash consideration for these redemptions totaled $1.6 billion, including make-whole premiums of $47 million, which resulted in a loss on extinguishment of debt of $54 million. The Company funded the redemptions with a portion of the net proceeds from the 2052 Notes offering and cash on hand.
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Guaranteed Senior Notes

The Guaranteed Senior Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P, are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness.

The Viper Notes are senior unsecured obligations of Viper, initially guaranteed on a senior unsecured basis by Viper LLC, and will pay interest semi-annually. The Company will not guarantee the Viper Notes. In the future, each of Viper’s restricted subsidiaries that either (i) guarantees any of its or LIBOR,a guarantor’s indebtedness, or (ii) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Viper Notes.

Viper’s Credit Agreement

On May 31, 2023, Viper LLC entered into a tenth amendment to the existing credit agreement, which among other things, (i) maintained the maximum credit amount of $2.0 billion, (ii) increased the borrowing base from $580 million to $1.0 billion and (iii) increased the aggregate elected commitment amount from $500 million to $750 million.

On September 22, 2023, Viper LLC entered into an eleventh and separately a twelfth amendment to the existing credit agreement, which among other things, (i) extended the maturity date from June 2, 2025, to September 22, 2028, (ii) maintained the maximum credit amount of $2.0 billion, (iii) further increased the borrowing base from $1.0 billion to $1.3 billion, (iv) further increased the aggregate elected commitment amount from $750 million to $850 million, and (v) waived the automatic reduction of the borrowing base that otherwise would have occurred upon the consummation of the issuance of the 2031 Notes.

As of December 31, 2023, Viper LLC had $263 million of outstanding borrowings and $587 million available for future borrowings under the Viper credit agreement. The weighted average interest rates on borrowings under the Viper credit agreement were 7.41%, 4.22%, and 2.35% for the years ended December 31, 2023, 2022 and 2021, respectively.

The outstanding borrowings under the Viper credit agreement bear interest at a rate elected by Viper LLC that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”), or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 1-month Adjusted Term SOFR plus 1.0%), in each case plus the applicable margin. The applicable margin ranges from 0.25%1.00% to 1.25%2.00% per annum in the case of the alternatealternative base rate and from 1.25%2.00% to 2.25%3.00% per annum in the case of LIBOR,Adjusted Term SOFR, in each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margin dependscase depending on the amount of the loans and letters of credit outstanding in relation to the commitment, which is defined ascalculated using the least of the maximum credit amount, the borrowing baseaggregate elected commitment amount and the elected commitment amount. The Companyborrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under theThe credit agreement is secured by substantially all the assets of Viper and (c) at the maturity date of November 1, 2022.Viper LLC.

The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, excess cash and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper credit agreementNot greater than 3.04.0 to 1.0
Ratio of current assets to liabilities, as defined in the Viper credit agreementNot less than 1.0 to 1.0
Ratio of secured debt to EBITDAX, as defined in the Viper credit agreementNot greater than 2.5 to 1.0

The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
As of December 31, 2017 and 2016, the Company2023, Viper LLC was in compliance with all financial maintenance covenants under its revolvingthe Viper credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.agreement.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and the Partnership had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Partnership that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the Partnership and its subsidiary’s assets.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial CovenantRequired Ratio
Ratio of total debt to EBITDAXNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Interest expense


The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 20162023, 2022 and 2015:2021:
Year Ended December 31,
202320222021
(In millions)
Interest expense$346 $272 $277 
Other fees and expenses2 12 11 
Less: interest income2 1 1 
Less: capitalized interest171 124 88 
Interest expense, net$175 $159 $199 

9.    STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

Common Stock Repurchase Programs

The Company’s board of directors has approved a common stock repurchase program to acquire up to $4.0 billion of the Company’s outstanding common stock, excluding excise tax. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the years ended December 31, 2023, 2022 and 2021, the Company repurchased, excluding excise tax, approximately $838 million, $1.1 billion and $431 million, respectively, of common stock under the respective repurchase programs. As of December 31, 2023, $1.6 billion remained available for use to repurchase shares under the Company’s common stock repurchase program, excluding excise tax.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler through the Effective Date of the Rattler Merger and are presented as a component of equity. The Company’s ownership percentages in Viper and Rattler have historically changed as a result of public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on their units. These changes in ownership percentage and the disproportionate allocation of net income to the Company result in adjustments to non-controlling interest and additional paid-in-capital, tax effected, but do not impact earnings.

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the respective periods:

Year Ended December 31,
202320222021
(In millions)
Net income (loss) attributable to the Company$3,143 $4,386 $2,182 
Change in ownership of consolidated subsidiaries77 (46)66 
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest$3,220 $4,340 $2,248 

99
 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Interest expense$60,671
 $39,642
 $40,221
Less capitalized interest(22,097) —
 —
Other fees and expenses2,160
 1,426
 1,292
Total interest expense$40,734
 $41,068
 $41,513


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Dividends
9.    CAPITAL STOCK AND EARNINGS PER SHARE

The following table presents dividends and distribution equivalent rights paid on the Company’s common stock during the respective periods:

BaseVariableTotalTotal
(In per share)(In millions)
2023
First quarter$0.80 $2.15 $2.95 $546 
Second quarter0.80 0.03 0.83 151 
Third quarter0.84 — 0.84 151 
Fourth quarter0.84 2.53 3.37 607 
Total year-to-date$3.28 $4.71 $7.99 $1,455 
2022
First quarter$0.60 $— $0.60 $108 
Second quarter0.70 2.35 3.05 548 
Third quarter0.75 2.30 3.05 532 
Fourth quarter0.75 1.51 2.26 400 
Total year-to-date$2.80 $6.16 $8.96 $1,588 
2021
First quarter$0.40 $— $0.40 $69 
Second quarter0.40 — 0.40 74 
Third quarter0.45 — 0.45 83 
Fourth quarter0.50 — 0.50 92 
Total year-to-date$1.75 $— $1.75 $318 

Viper’s Common Stock Repurchase Program

Viper’s board of directors has currently approved a common stock repurchase program to acquire up to $750 million of Viper’s outstanding Class A common stock, excluding excise tax, over an indefinite period of time. During the years ended December 31, 2023, 2022 and 2021, Viper repurchased approximately $95 million, $151 million, and $46 million under its repurchase program. As of December 31, 2023, $434 million remained available for use to repurchase shares under Viper’s common stock repurchase program.

Dividends to Non-Controlling Interest

During the years ended December 31, 2023, 2022 and 2021 Viper paid $129 million, $182 million, and $76 million of distributions and dividends to its public shareholders, excluding Diamondback, completedin accordance with the following equity offeringsdividend policy approved by its board of directors. Prior to the Rattler Merger, Rattler made $35 million and $36 million of distributions to its common unitholders during the years ended December 31, 2017, 20162022 and 2015:2021, respectively, in accordance with the distribution policy approved by its board of directors. These dividends are reflected under the caption “Dividends/distributions to non-controlling interest” on the Company’s consolidated statement of stockholders’ equity and consolidated statements of cash flows.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

DateNumber of Shares of Common Stock SoldNumber of Shares of Common Stock Issued to UnderwritersPrice per Share Sold to UnderwritersProceeds Received by the Company
January 20152,012,500262,500
$59.34
$119,422
May 20154,600,000600,000
$72.53
$333,638
August 20152,875,000375,000
$68.74
$197,628
January 20164,600,000600,000
$55.33
$254,518
July 20166,325,000825,000
$87.24
$551,777
December 201612,075,0001,575,000
$95.3025
$1,150,828

Earnings (Loss) Per Share


The Company’s basic earnings (loss) per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of Viper and Rattler prior to the PartnershipEffective Date of the Rattler Merger are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.subsidiaries.

A reconciliation of the components of basic and diluted earnings (loss) per common share is presented in the table below:
Year Ended December 31,
202320222021
(In millions, except per share amounts)
Net income (loss) attributable to common stock$3,143 $4,386 $2,182 
Less: distributed and undistributed earnings allocated to participating securities(1)
22 42 20 
Net income (loss) attributable to common stockholders$3,121 $4,344 $2,162 
Weighted average common shares outstanding:
Basic weighted average common shares outstanding179,999 176,539 176,643 
Effect of dilutive securities:
Weighted-average potential common shares issuable— — — 
Diluted weighted average common shares outstanding179,999 176,539 176,643 
Basic net income (loss) attributable to common stock$17.34 $24.61 $12.24 
Diluted net income (loss) attributable to common stock$17.34 $24.61 $12.24 
 Year Ended December 31,
 2017 2016 2015
    
Net income (loss) attributable to common stock$482,261
 $(165,034) $(550,628)
Weighted average common shares outstanding     
Basic weighted average common units outstanding97,458
 75,077
 63,019
Effect of dilutive securities:     
Potential common shares issuable230
 —
 —
Diluted weighted average common shares outstanding97,688
 75,077
 63,019
Basic net income (loss) attributable to common stock$4.95
 $(2.20) $(8.74)
Diluted net income (loss) attributable to common stock$4.94
 $(2.20) $(8.74)

For the years ended December 31, 2017, 2016(1)    Unvested restricted stock awards and 2015, there were 45,690 shares, 243,654 sharesperformance stock awards that contain non-forfeitable distribution equivalent rights are considered participating securities and 100,924 shares, respectively, that were nottherefore are included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive forcalculation pursuant to the periods presented but could potentially dilute basic earnings per share in future periods.two-class method.


10.    EQUITY-BASED COMPENSATION


On October 10, 2012,Under the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Planequity incentive plan (the “2012“Equity Plan”), whichapproved by the board of directors, the Company is intendedauthorized to provide eligible employees with equity-based incentives. The 2012 Plan provides for the grantingissue up to 11.8 million shares of incentive stock options, nonstatutoryand non-statutory stock options, restricted stock awards (restricted stock and restricted stock units),units, performance awards and stock appreciation rights or any combination of the foregoing. A total of 2,500,000 shares of the Company’s common stock has been reserved for issuance pursuant to this plan.


F-22


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The following table presents the effects of the equity and stock based compensation plans and related costs:
 2017 2016 2015
 (In thousands)
General and administrative expenses$25,537
 $26,453
 $18,529
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties8,641
 7,079
 6,043

On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,070,356 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof.

Stock Options

In accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisable ratably over a five-year period. However, as described above, options associated with the modification vest in four substantially equal annual installments and are exercisable for five years from the date of grant.

The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year.

The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2017.
   Weighted Average  
   Exercise Remaining Intrinsic
 Options Price Term Value
     (in years) (in thousands)
Outstanding at December 31, 201615,750
 $22.72
    
Exercised(15,750) $22.72
    
Outstanding at December 31, 2017—
 $—
 0.00 $—

The aggregate intrinsic value of stock options that were exercised during the years ended December 31, 2016 and 2015 was $1.3 million and $15.7 million, respectively.

Restricted Stock Units

Under the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company currently has outstanding restricted stock units and performance-based restricted stock units under the Equity Plan. The Company also has immaterial amounts of restricted share awards and stock appreciation rights outstanding which were issued under plans assumed in connection with previously completed mergers. At December 31, 2023, approximately 5.1 million shares of common stock remain available for future grants under the Equity Plan. The Company classifies its restricted stock units and performance-based restricted stock units as equity-based awards and estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period.



In addition to the Equity Plan, Viper maintains its own long-term incentive plan, which is not significant to the Company.

The following table presents the financial statement impacts of equity compensation plans and related costs on the Company’s financial statements:
Year Ended December 31,
202320222021
(In millions)
General and administrative expenses$54 $55 $51 
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties$26 $21 $20 

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Restricted Stock Units

The following table presents the Company’s restricted stock unitsunit activity under the 2012 Plan during the year ended December 31, 2017.2023 under the Equity Plan:
Restricted Stock
 Units		Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2022918,902 $95.74 
Granted464,367 $145.45 
Vested(558,077)$85.94 
Forfeited(73,996)$108.00 
Unvested at December 31, 2023751,196 $132.29 
 Restricted Stock
Awards & Units		 Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2016206,004
 $70.33
Granted188,438
 $102.77
Vested(147,934) $77.44
Forfeited(2,931) $89.21
Unvested at December 31, 2017243,577
 $90.88


The aggregate grant date fair value of restricted stock units that vested during the yearyears ended December 31, 2017, 20162023, 2022 and 20152021 was $14.8$48 million, $12.5$41 million and $10.1$46 million, respectively. As of December 31, 2017,2023, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $14.4 million. Such cost$74 million, which is expected to be recognized over a weighted-average period of 1.51.9 years.


Performance-Based Restricted Stock Units


To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period.


In February 2015,March 2023, eligible employees received performance restricted stock unit awards totaling 90,249126,347 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2023 to December 31, 2025 and cliff vest at December 31, 2025 subject to continued employment. The initial payout of the March 2023 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%. Additionally, in July 2023 the Company granted 1,858 units under substantially the same terms as the March 2023 performance restricted stock unit awards.

In March 2022, eligible employees received performance restricted stock unit awards totaling 126,905 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2022 to December 31, 2024 and cliff vest at December 31, 2024 subject to continued employment. The initial payout of the March 2022 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.

In March 2021, eligible employees received performance restricted stock unit awards totaling 198,454 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have aawarded based upon the TSR during the three-year performance period of January 1, 20142021 to December 31, 2016 and2023. These awards cliff vested at 250% on December 31, 2016.2023 based upon the results of the TSR during the performance period.

In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2017 and vested at December 31, 2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2018 and cliff vest at December 31, 2018.

In February 2017, eligible employees received performance restricted stock unit awards totaling 37,440 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2018 and cliff vest at December 31, 2018. Eligible employees received additional performance restricted stock unit awards totaling 74,880 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2019 and cliff vest at December 31, 2019.


The fair value of each performance restricted stock unit issuance is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period.

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.assumptions for the awards granted during the periods presented:
March 2023July 202320222021
Grant-date fair value$259.52 $222.09 $237.13 $131.06 
Risk-free rate4.64 %4.70 %1.44 %15.00 %
Company volatility46.90 %47.20 %72.10 %69.60 %
102
 2017 2016  
 Two-Year Performance Period Three-Year Performance Period Two-Year Performance Period Three-Year Performance Period 2015
Grant-date fair value$162.13
 $168.73
 $103.41
 $102.35
 $137.14
Risk-free rate1.27% 1.59% 0.86% 1.10% 0.49%
Company volatility39.32% 41.14% 41.91% 42.16% 43.36%


F-24


Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



The following table presents the Company’s performance restricted stock unit activity under the 2012Equity Plan for the year ended December 31, 2017.2023:
Performance Restricted Stock UnitsWeighted Average Grant-Date Fair Value
Unvested at December 31, 2022347,881 $168.48 
Granted361,268 $258.98 
Vested(388,436)$134.64 
Forfeited(42,657)$144.48 
Unvested at December 31, 2023(1)
278,056 $234.80 
 Performance Restricted Stock Units Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016252,471
 $103.06
Granted118,169
 $166.53
Vested(168,314) $103.41
Unvested at December 31, 2017(1)
202,326
 $139.83
(1)A maximum of 645,703 units could be awarded based upon the Company’s final TSR ranking.
(1)A maximum of 404,652 units could be awarded based upon the Company’s final TSR ranking.


As of December 31, 2017,2023, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $15.6 million. Such cost$35 million, which is expected to be recognized over a weighted-average period of 1.42.0 years.


Partnership Unit Options

In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options will become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempts to exercise a vested unit option and the fair market value per unit as of such date is less than the exercise price per option unit, the vested unit option will not be exercisable. At the end of the Exercise Period, any vested unit option that is not exercisable or that has not been exercised will automatically terminate and become null and void.

The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.
 2015
Grant-date fair value$4.24
Expected volatility36.0%
Expected dividend yield5.9%
Expected term (in years)3.0
Risk-free rate0.99%


F-25


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017.
   Weighted Average  
 Unit Options Exercise Price Remaining Term Intrinsic Value
     (in years) (in thousands)
Outstanding at December 31, 20162,424,266
 $26.00
    
Forfeited(2,416,666) $26.00
    
Outstanding at December 31, 20177,600
 $18.49
 0.00 $—
        
Vested and Expected to vest at December 31, 20177,600
 $18.49
 0.00 $—

Phantom Units

Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017.
 Phantom Units Weighted Average Grant-Date
Fair Value
Unvested at December 31, 201621,048
 $16.23
Granted116,567
 $17.09
Vested(32,176) $16.49
Unvested at December 31, 2017105,439
 $17.10

The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million. As of December 31, 2017, the unrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

11.    RELATED PARTY TRANSACTIONS

Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of December 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding common stock. The Chairman of the Board of Directors of both the Company and the General Partner was a partner at Wexford until his retirement from Wexford effective December 31, 2016. Another partner at Wexford serves as a member of the Board of Directors of the General Partner. Beginning January 1, 2017, Wexford and entities affiliated with Wexford are no longer considered related parties of the Company and any expenses after December 31, 2016 are no longer classified as related party expenses.

Related Party Revenue and Expenses

During the year ended December 31, 2016, the Company paid $3.3 million in lease operating expenses and $2.2 million in general and administrative expenses to related parties. During the year ended December 31, 2016, the Company received $0.2 million in other income from related parties. During the year ended December 31, 2015, the Company paid $0.2 million in lease operating expenses, $0.2 million in production and ad valorem taxes, $1.0 million in gathering and transportation expenses and $2.3 million in general and administrative expenses to related parties. During the year ended December 31, 2015, the Company received $0.2 million in other income from related parties.

Advisory Services Agreement - The Company

The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company paid $0.5 million during both of the years ended December 31, 2016 and 2015 under the Advisory Services Agreement.

Advisory Services Agreement - The Partnership

In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership or the General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and the General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s or the General Partner’s request in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partner’s day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Partnership did not pay any amounts during the years ended December 31, 2017 and 2016 under the Viper Advisory Services Agreement. The Partnership paid $0.5 million during the year ended December 31, 2015 under the Viper Advisory Services Agreement.


Coronado Midstream

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMar Gas LLC, an entity that was affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. An entity controlled by Wexford had owned approximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party.

Midland Leases

Effective May 15, 2011, the Company occupied corporate office space in the Fasken building in Midland, Texas under a lease with an initial term of five years. On November 10, 2014, the lease was amended to extend the term of the lease for an additional 10-year period and to increase the monthly base rent to $94,000 beginning in June 2016, with an increase of approximately 2% annually. The office space is owned by Fasken, which is an entity controlled by an affiliate of Wexford.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The following table contains amendments made to lease additional office space in the Midland corporate office during the years ended December 31, 2016 and 2015:
Date of AmendmentsRent for Additional SpaceApprox. Annual Increase of Monthly Base Rent
2nd quarter 2014
$27,000N/A
4th quarter 2014
$53,0004%
April 2015$23,000N/A
June 2015$22,0002%

Field Office Lease

The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011. On March 1, 2014, the building was purchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. The monthly base rent was $11,000 and increased 3% annually on March 1 of each year. During the third quarter of 2014, the Company entered into a sublease with Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term. The Company paid rent of $0.2 million during both of the years ended December 31, 2016 and 2015. The Company received payments of $0.2 million from Bison in respect of this sublease during both of the years ended December 31, 2016 and 2015. During the second quarter of 2017, the sublease between the Company and Bison as well as the original lease between the Company and WT Commercial Portfolio, LLC were terminated.

The Partnership - Lease Bonus
During the year ended December 31, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, the Company paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.
12.    INCOME TAXES


Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The Company and its subsidiaries, other than Viper, Viper LLC, and Rattler LLC, file a U.S. federal corporate income tax return on a consolidated basis. As discussed further below, Viper became a taxable entity for U.S. federal income tax purposes effective May 10, 2018, and as such files a U.S. federal corporate income tax return including the activity of its investment in Viper LLC. Viper’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest.


For certain reportingperiods subsequent to the Effective Date of the Rattler Merger, Rattler is a member of the group filing consolidated income tax returns with Diamondback Energy, Inc. and its subsidiaries. As such, Rattler’s current and deferred income taxes continue to be included in the Company’s consolidated income tax expense from continuing operations and, only for periods prior to the quarterRattler Merger, in net income attributable to the non-controlling interest.

The Company’s effective income tax rates were 21.5%, 20.5% and 21.7% for the years ended December 31, 2017,2023, 2022 and 2021, respectively. Total income tax expense for the Company’s deferredyear ended December 31, 2023 differed from amounts computed by applying the U.S. federal statutory tax assets exceeded its deferredrate to pre-tax income primarily due to state income taxes, net of federal benefit, partially offset by the impact of permanent differences between book and taxable income and tax liabilities. Thebenefit resulting net deferred tax asset was subject tofrom a fullreduction in the valuation allowance. The Company continually assesses itsallowance on Viper’s deferred tax assets for realizability and, as a result of such reassessment, in the quarter ended December 31, 2017 the Company determined that sufficient evidence existed to indicate that it is probable that its deferred tax assets will be realized primarily through the unfavorable reversal of deferred tax liabilities, which currently exceed the Company’s deferred tax assets. In the quarter ended December 31, 2017, the valuation allowance historically applied against the Company’s gross deferred tax assets was removed. The Company’s gross deferred tax assets were recorded based upon the 35% federal income tax rate that was in effect prior to the enactment of the Tax Cut and Jobs Act. Subsequently, but also in the quarter ended December 31, 2017, the Company’s deferred tax assets and deferred tax liabilities were revalued to reflect the federal income tax rate enacted by the Tax Cut and Jobs Act. The effects of the removal of the valuation allowance and the reduction to the federal income tax rate may both be seen in the reconciliation of our effective tax rate to the statutory rate below.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. Among other significant features, the Tax Cut and Jobs Act reduces the maximum US federal corporate income tax rate from 35% to 21%, preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling costs, allows for immediate expensing of capital expenditures for tangible personal property for a period of time, modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations, and enacts new limitations regarding the deductibility of interest expense.

As of the completion of the Company’s financial statements for its year ended December 31, 2017, the Company has substantially completed its accounting2023. Total income tax expense for the effectsyear ended December 31, 2022 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income for the period primarily due to (i) state income taxes, net of federal benefit, partially offset by (ii) the impact of permanent differences between book and taxable income and (iii) tax benefit resulting from a reduction in the valuation allowance on Viper’s and QEP’s deferred tax assets for the year ended December 31, 2022. Total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income for the period primarily due to state income taxes, net of federal benefit.

The Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which created a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion of average adjusted pre-tax net income on their consolidated financial statements) as well as an excise tax of 1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022. Based on application of currently available guidance, the Company’s income tax expense for the year ended December 31, 2023 was not impacted by the CAMT. The Company’s excise tax during the year ended December 31, 2023 was immaterial and was recognized as part of the enactmentcost basis of the Tax Cut and Jobs Act. With respect to those itemsunits repurchased.


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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



for which the Company’s accounting is not complete, as described below, the Company has made reasonable estimates of the effects on its existing deferred tax balances. In all cases, the Company will continue to make and refine its calculations as additional analysis is completed.

To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, which is generally a federal income tax rate of 21%. The enacted rate change resulted in a non-cash decrease of approximately $67.9 million to the Company’s income tax provision for the period ended December 31, 2017 and a corresponding reduction to the Company’s net noncurrent deferred tax liability balance as of December 31, 2017.

The Company is still analyzing certain aspects of the Tax Cuts and Jobs Act, specifically the provisions related to limitations on the deductibility of certain executive compensation, including equity based compensation. The Company is refining its calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018.

At December 31, 2017, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2014 through 2017 remain subject to examination by the major tax jurisdictions.

The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2017, 20162023, 2022 and 20152021 are as follows:

Year Ended December 31,
202320222021
(In millions)
Current income tax provision (benefit):
Federal$505 $421 $10 
State29 33 15 
Total current income tax provision (benefit)534 454 25 
Deferred income tax provision (benefit):
Federal370 706 594 
State8 14 12 
Total deferred income tax provision (benefit)378 720 606 
Total provision for (benefit from) income taxes$912 $1,174 $631 
 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Current income tax provision (benefit):     
Federal$—
 $—
 $(33)
State999
 192
 268
Total current income tax provision999
 192
 235
Deferred income tax provision (benefit):     
Federal(21,720) (579) (198,729)
State1,153
 579
 (2,816)
Total deferred income tax provision (benefit)(20,567) —
 (201,545)
Total provision for (benefit from) income taxes$(19,568) $192
 $(201,310)

A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows:
Year Ended December 31,
202320222021
(In millions)
Income tax expense (benefit) at the federal statutory rate (21%)$892 $1,205 $610 
State income tax expense, net of federal tax effect31 42 23 
Non-deductible compensation8 10 10 
Change in valuation allowance(7)(71)(12)
Other, net(12)(12)— 
Provision for (benefit from) income taxes$912 $1,174 $631 
 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Income tax expense (benefit) at the federal statutory rate (35%)$174,016
 $(57,694) $(263,179)
Impact of nontaxable noncontrolling interest(12,073) —
 —
Income tax benefit relating to change in statutory tax rate(67,938) —
 (1,145)
State income tax expense (benefit), net of federal tax effect3,413
 770
 (2,548)
Non-deductible compensation13,492
 3,990
 1,354
Change in valuation allowance(127,485) 53,336
 61,056
Other, net(2,993) (210) 3,152
Provision for (benefit from) income taxes$(19,568) $192
 $(201,310)


F-29


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



The components of the Company’s deferred tax assets and liabilities as of December 31, 20172023 and 20162022 are as follows:

December 31,
20232022
(In millions)
Deferred tax assets:
Net operating loss and other carryforwards$236 $406 
Derivative instruments22 — 
Stock based compensation7 5 
Viper's investment in Viper LLC170 148 
Rattler's investment in Rattler LLC— 1 
Other21 16 
Deferred tax assets456 576 
Valuation allowance(233)(223)
Deferred tax assets, net of valuation allowance223 353 
Deferred tax liabilities:
Oil and natural gas properties and equipment2,463 2,109 
Midstream investments162 235 
Derivative instruments— 12 
Other2 2 
Total deferred tax liabilities2,627 2,358 
Net deferred tax liabilities$2,404 $2,005 
104
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

 December 31,
 2017 2016
 (In thousands)
Current:   
Deferred tax assets   
Derivative instruments$—
 $7,771
Other—
 3,518
Current deferred tax assets—
 11,289
Valuation allowance—
 (11,289)
Current deferred tax assets, net of valuation allowance—
 —
Deferred tax liabilities   
Derivative instruments—
 —
Total current deferred tax liabilities—
 —
Net current deferred tax assets—
 —
Noncurrent:   
Deferred tax assets   
Net operating loss carryforwards (subject to 20 year expiration)74,997
 139,065
Derivative instruments22,918
 —
Stock based compensation942
 6,234
Other2,464
 —
Noncurrent deferred tax assets101,321
 145,299
Valuation allowance(104) (103,112)
Noncurrent deferred tax assets, net of valuation allowance101,217
 42,187
Deferred tax liabilities   
Oil and natural gas properties and equipment202,997
 42,187
Midstream assets6,268
 —
Total noncurrent deferred tax liabilities209,265
 42,187
Net noncurrent deferred tax liabilities108,048
 —
Net deferred tax liabilities$108,048
 $—


The Company incurred ahad net deferred tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drillingliabilities of approximately $2.4 billion and development costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. $2.0 billion at December 31, 2023 and 2022, respectively.

At December 31, 2017,2023, the Company had approximately $357.0$369 million of federal NOLs and $4 million of federal tax credits expiring in 2032 through 2037.2037 and $221 million of federal NOLs with an indefinite carryforward life, including NOLs acquired from QEP and from Rattler. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company believes thatCompany’s federal tax attributes, including those acquired from QEP and Rattler, are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period,period. Other than as described below regarding realization of tax attributes acquired from QEP, the Company believes that the application of Section 382 of the Code will not have an adverse effect on future NOL usage.usage of the Company’s NOLs and credits.


On August 24, 2022, the Company completed the Rattler Merger. Management considered the likelihood that the federal net operating losses and other tax attributes acquired from Rattler will be utilized, including in light of Rattler’s inclusion in consolidated income tax returns with Diamondback for periods subsequent to the Rattler Merger, and in light of the annual limitation on utilization of tax attributes following Rattler’s ownership change pursuant to Section 382 of the Code. As a result of the assessment, including consideration of all available positive and negative evidence, management determined that it continues to be more likely than not that Rattler will realize its deferred tax assets as of December 31, 2023.

As of December 31, 2017,2023, the Company hashad a remaining valuation allowance of $0.1$11 million forrelated to federal NOL and credit carryforwards acquired from QEP which are estimated not more likely than not to be realized prior to expiration.In addition, the Company had a valuation allowance of $107 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate significant future operations in those states. In the fourth quarter of 2017, the Company removed itsstates and a valuation allowance againstof $114 million related to Viper’s deferred tax assets, for U.S. NOL carryforwards resulting in income tax benefit of $127.5 million. Asas discussed above, management’sfurther below. Management’s assessment at each balance sheet date included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities.liabilities and the limitations imposed by Section 382 of the Code on certain of the Company’s NOLs and other carryforwards. Management believes that the balance of the Company’s NOLs areis realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As a result of management’s assessment, in the quarter ended December 31, 2017,2023, management determined that it is more likely than not that the Company has removedwill realize its valuation allowance against its federal NOLs and other federalremaining deferred tax assets.

At December 31, 2023, the Company’s net deferred tax liabilities include deferred tax assets of approximately $170 million related to Viper’s investment in orderViper LLC. Deferred taxes are provided on the difference between Viper’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Viper LLC.

As of December 31, 2023, Viper had a valuation allowance of approximately $114 million related to state its deferred tax assets and liabilities at the amountthat Viper does not believe are more likely than not to be realized. During the years ended December 31, 2023 and 2022, Viper recognized deferred income tax benefit of $7 million and $50 million, respectively, related to a reduction in its valuation allowance, based on a change in judgment about the realizability of its deferred tax assets. Management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards, resulted in recognition of tax benefit for the portion of Viper’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. Viper retained a partial valuation allowance on its deferred tax assets due in part to potential future volatility in commodity prices impacting the likelihood of future realizability.


F-30
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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



The following table sets forth changes in the Company’s unrecognized tax benefits:

December 31,
20232022
(In millions)
Balance at beginning of year$7 $7 
Decrease resulting from expiration of statute(7)— 
Balance at end of year— 7 
Less: Effects of temporary items— (4)
Total that, if recognized, would impact the effective income tax rate as of the end of the year$— $3 

13.The Company recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. The Company’s federal and state income tax returns for the years ended December 31, 2020 through December 31, 2022 remain open for all purposes of examination by the IRS and major state taxing jurisdictions. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization. It is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2023 and 2022, there was an insignificant amount of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

12. DERIVATIVES


At December 31, 2023, the Company has commodity derivative contracts and interest rate swaps outstanding. All derivative financial instruments are recorded at fair value in the accompanying balance sheet. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap and fixed price basis contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price. Under the Company’s costless collar contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the put option price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. If the settlement price is between the put and the call price, there is no payment required. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of December 31, 2017, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
 2018 2019
 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI9,761,000 $51.10
 1,095,000 $49.82
Oil Swaps - BRENT1,830,000 $54.89
 0 $—
Oil Basis Swaps5,475,000 $0.88
 0 $—
Natural Gas Swaps7,750,000 $3.14
 0 $—

 Floor Ceiling
 Volume
(Bbls)		 Fixed Price (per Bbl) Volume
(Bbls)		 Fixed Price (per Bbl)
January 2018 - March 2018       
Costless Collars540,000 $47.00
 270,000 $56.34

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.


F-31


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2017 and 2016.

 December 31,
 2017 2016
 (in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet$531
 $709
Net amounts of assets presented in the Consolidated Balance Sheet531
 709
    
Gross amounts of liabilities presented in the Consolidated Balance Sheet106,670
 22,608
Net amounts of liabilities presented in the Consolidated Balance Sheet$106,670
 $22,608

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
 December 31,
 2017 2016
 (in thousands)
Current assets: derivative instruments$531
 $—
Noncurrent assets: derivative instruments—
 709
Total assets$531
 $709
Current liabilities: derivative instruments$100,367
 $22,608
Noncurrent liabilities: derivative instruments6,303
 —
Total liabilities$106,670
 $22,608

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:
 Year Ended December 31,
 2017 2016 2015
 (in thousands)
Change in fair value of open non-hedge derivative instruments$(84,240) $(26,522) $(112,918)
Gain on settlement of non-hedge derivative instruments6,728
 1,177
 144,869
Gain (loss) on derivative instruments$(77,512) $(25,345) $31,951

14.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.


Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016.
 December 31,
 2017 2016
 (in thousands)
Fixed price swaps:   
Quoted prices in active markets level 1$—
 $—
Significant other observable inputs level 2(106,139) 23,317
Significant unobservable inputs level 3—
 —
Total$(106,139) $23,317


Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets.
 December 31, 2017 December 31, 2016
 Carrying   Carrying  
 Amount Fair Value Amount Fair Value
 (in thousands)
Debt:       
Revolving credit facility$397,000
 $397,000
 $—
 $—
4.750% Senior Notes due 2024500,000
 501,855
 500,000
 491,250
5.375% Senior Notes due 2025500,000
 515,000
 500,000
 502,850
Partnership revolving credit facility93,500
 93,500
 120,500
 120,500

The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2017 quoted market price, a Level 1 classification in the fair value hierarchy.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


15.    COMMITMENTS AND CONTINGENCIES

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2017:
Year Ending December 31,Drilling Rig Commitments Office and Equipment Leases
 (in thousands)
2018$21,882
 $3,581
201910,082
 3,307
2020—
 2,927
2021—
 2,406
2022—
 2,242
Thereafter—
 7,973
Total$31,964
 $22,436

The Company leases office space in Midland, Texas and in Oklahoma City, OK from unrelated third parties. The following table presents rent expense for the years ended December 31, 2017, 2016 and 2015.

 Year ended December 31,
 2017 2016 2015
 (in thousands)
Rent Expense$2,412
 $1,961
 $1,449

Drilling contracts

As of December 31, 2017, the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2017 total approximately $32.0 million.

Oil production purchase agreement

On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading (US) Company, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading (US) Company upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of five years from the completion date. The Company’s maximum delivery obligation under this agreement is 8,000 gross barrels per day. The Company has a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, the Company has agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency

F-34


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)


volume is calculated. The agreement may be terminated by Shell Trading (US) Company in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated.

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest immediately. For the years ended December 31, 2017, 2016 and 2015 the Company paid $1.8 million, $1.2 million and $1.4 million, respectively, in contributions to the plan.

16.    SUBSEQUENT EVENTS

Commodity Contracts


SubsequentThe Company has entered into multiple crude oil and natural gas derivatives, indexed to December 31, 2017,the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into new fixed price swapscommodity derivative instruments only with counterparties that are also lenders under its credit facility and costless collars with corresponding put and call options. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing.

The following tables presenthave been deemed an acceptable credit risk. As such, collateral is not required from either the derivative contracts entered into bycounterparties or the Company subsequent to December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed.on its outstanding commodity derivative contracts.


106
 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu)
July 2018 - December 2018   
Oil Swaps - WTI184,000 $60.70
January 2019 - March 2019   
Oil Swaps - WTI90,000 $58.70

Fasken Building Purchase

On January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located.

New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility

On January 29, 2018, the Company closed on the private placement issuance of $300.0 million aggregate principal amount of 5.375% Senior Notes due 2025. In the offering, the Company received approximately $308.4 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest. The Company used all of the net proceeds from the offering to repay a portion of the outstanding borrowings under its revolving credit facility. In connection with the offering, the lenders under the Company’s revolving credit facility waived the borrowing base decrease that would have been triggered in connection with the offering. Immediately following the completion of the offering and the application of the net proceeds thereof, the Company’s borrowing base remained $1.8 billion, the Company’s elected commitment was $1.0 billion, and the Company had $911.4 million of available borrowing capacity under its revolving credit facility.

17.    GUARANTOR FINANCIAL STATEMENTS

As of December 31, 2017, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



As of December 31, 2023, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:
information may
SwapsCollars
Settlement MonthSettlement YearType of ContractBbls/MMBtu Per DayIndexWeighted Average DifferentialWeighted Average Floor PriceWeighted Average Ceiling Price
OIL
Jan. - Jun.2024Costless Collar6,000WTI Cushing$—$65.00$95.55
Jan. - Dec.2024
Basis Swap(1)
10,000Argus WTI Midland$1.19$—$—
Jan. - Dec.2024Roll Swap30,000WTI$0.81$—$—
Jul. - Dec.2024Costless Collar4,000WTI Cushing$—$55.00$93.66
NATURAL GAS
Jan. - Dec.2024Costless Collar290,000Henry Hub$—$2.83$7.52
Jan. - Dec.2024
Basis Swap(1)
380,000Waha Hub$(1.18)$—$—
Jan. - Dec.2025
Basis Swap(1)
310,000Waha Hub$(0.69)$—$—
(1)    The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

Settlement MonthSettlement YearType of ContractBbls Per DayIndexStrike PriceDeferred Premium
OIL
Jan. - Mar.2024Put124,000Brent$55.40$1.48
Jan. - Mar.2024Put32,000Argus WTI Houston$55.00$1.60
Jan. - Mar.2024Put16,000WTI Cushing$58.13$1.54
Apr. - Jun.2024Put108,000Brent$55.46$1.49
Apr. - Jun.2024Put26,000Argus WTI Houston$55.00$1.56
Apr. - Jun.2024Put14,000WTI Cushing$59.29$1.51
Jul. - Sep.2024Put66,000Brent$55.15$1.53
Jul. - Sep.2024Put18,000Argus WTI Houston$55.00$1.55
Jul. - Sep.2024Put2,000WTI Cushing$55.00$1.53
Oct. - Dec.2024Put34,000Brent$55.00$1.61
Oct. - Dec.2024Put4,000Argus WTI Houston$55.00$1.72
Oct. - Dec.2024Put2,000WTI Cushing$55.00$1.53


Interest Rate Swaps

In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million, which were designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) at inception. The Company receives a fixed 3.50% rate of interest on these swaps. Effective on May 28, 2023, the variable rate of interest the Company pays on these swaps was reset from three month LIBOR to three month SOFR plus 2.1865%. The Company previously adopted the optional expedient in ASU 2020-04, “Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting,” as later extended for these contract term modifications, and as a result, did not necessarily be indicativerecognize any impact of the change in reference rate on its financial position, results of operations cash flows or financial position hadliquidity for the Guarantor Subsidiaries operated as independent entities.year ended December 31, 2023.

In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued. The Company has not presented separate financial and narrative information for eachcumulative fair value basis adjustment recorded on the 2029 Notes at the time of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.

107
Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$54,074
 $34,175
 $24,197
 $—
 $112,446
Accounts receivable—
 205,859
 25,754
 —
 231,613
Accounts receivable - related party—
 —
 5,142
 (5,142) —
Intercompany receivable2,624,810
 2,267,308
 —
 (4,892,118) —
Inventories—
 9,108
 —
 —
 9,108
Other current assets618
 4,461
 355
 —
 5,434
Total current assets2,679,502
 2,520,911
 55,448
 (4,897,260) 358,601
Property and equipment:         
Oil and natural gas properties, at cost, full cost method of accounting—
 8,129,211
 1,103,897
 (414) 9,232,694
Midstream assets—
 191,519
 —
 —
 191,519
Other property, equipment and land—
 80,776
 —
 —
 80,776
Accumulated depletion, depreciation, amortization and impairment—
 (1,976,248) (189,466) 4,342
 (2,161,372)
Net property and equipment—
 6,425,258
 914,431
 3,928
 7,343,617
Funds held in escrow—
 —
 6,304
 —
 6,304
Derivative instruments—
 —
 —
 —
 —
Investment in subsidiaries3,809,557
 —
 —
 (3,809,557) —
Other assets—
 25,609
 36,854
 —
 62,463
Total assets$6,489,059
 $8,971,778
 $1,013,037
 $(8,702,889) $7,770,985
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$1
 $91,629
 $2,960
 $—
 $94,590
Intercompany payable132,067
 4,765,193
 —
 (4,897,260) —
Other current liabilities7,236
 472,933
 2,669
 —
 482,838
Total current liabilities139,304
 5,329,755
 5,629
 (4,897,260) 577,428
Long-term debt986,847
 397,000
 93,500
 —
 1,477,347
Derivative instruments—
 6,303
 —
 —
 6,303
Asset retirement obligations—
 20,122
 —
 —
 20,122
Deferred income taxes108,048
 —
 —
 —
 108,048
Total liabilities1,234,199
 5,753,180
 99,129
 (4,897,260) 2,189,248
Commitments and contingencies         
Stockholders’ equity5,254,860
 3,218,598
 913,908
 (4,132,506) 5,254,860
Non-controlling interest—
 —
 —
 326,877
 326,877
Total equity5,254,860
 3,218,598
 913,908
 (3,805,629) 5,581,737
Total liabilities and equity$6,489,059
 $8,971,778
 $1,013,037
 $(8,702,889) $7,770,985

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



dedesignation totaled $135 million. This basis adjustment is being amortized to interest expense over the remaining term of the 2029 Notes utilizing the effective interest method. See Note 8—Debt for further details. The dedesignated interest rate swaps are considered economic hedges of the Company’s fixed-rate debt. As such, changes in the fair value of the interest rate swaps after the date of dedesignation have been recorded in earnings under the caption “Gain (loss) on derivative instruments, net” in the consolidated statements of operations.

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 13—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the consolidated statements of operations:

Year Ended December 31,
202320222021
(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts$(239)$(528)$(978)
Interest rate swaps(20)(58)130 
Total$(259)$(586)$(848)
Net cash received (paid) on settlements:
Commodity contracts(1)
$(61)$(849)$(1,305)
Interest rate swaps(2)
(49)(1)80 
Total$(110)$(850)$(1,225)
(1)The years ended December 31, 2022 and 2021 include cash paid on commodity contracts terminated prior to their contractual maturity of $138 million and $16 million, respectively.
(2)The year ended December 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

13.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

108
Condensed Consolidated Balance Sheet
December 31, 2016
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$1,643,226
 $14,135
 $9,213
 $—
 $1,666,574
Restricted cash—
 —
 500
 —
 500
Accounts receivable—
 109,782
 10,043
 —
 119,825
Accounts receivable - related party—
 297
 3,470
 (3,470) 297
Intercompany receivable3,060,566
 359,502
 —
 (3,420,068) —
Inventories—
 1,983
 —
 —
 1,983
Other current assets481
 2,319
 187
 —
 2,987
Total current assets4,704,273
 488,018
 23,413
 (3,423,538) 1,792,166
Property and equipment:         
Oil and natural gas properties, at cost, full cost method of accounting—
 4,400,002
 760,818
 (559) 5,160,261
Midstream assets—
 8,362
 —
 —
 8,362
Other property, equipment and land—
 58,290
 —
 —
 58,290
Accumulated depletion, depreciation, amortization and impairment—
 (1,695,701) (148,948) 8,593
 (1,836,056)
Net property and equipment—
 2,770,953
 611,870
 8,034
 3,390,857
Funds held in escrow—
 121,391
 —
 —
 121,391
Derivative instruments—
 709
 —
 —
 709
Investment in subsidiaries(15,500) —
 —
 15,500
 —
Other assets—
 9,291
 35,266
 —
 44,557
Total assets$4,688,773
 $3,390,362
 $670,549
 $(3,400,004) $5,349,680
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$30
 $45,838
 $1,780
 $—
 $47,648
Accounts payable-related party1
 —
 —
 —
 1
Intercompany payable—
 3,423,538
 —
 (3,423,538) —
Other current liabilities5,868
 155,454
 371
 —
 161,693
Total current liabilities5,899
 3,624,830
 2,151
 (3,423,538) 209,342
Long-term debt985,412
 —
 120,500
 —
 1,105,912
Asset retirement obligations—
 16,134
 —
 —
 16,134
Total liabilities991,311
 3,640,964
 122,651
 (3,423,538) 1,331,388
Commitments and contingencies         
Stockholders’ equity3,697,462
 (250,602) 547,898
 (297,296) 3,697,462
Non-controlling interest—
 —
 —
 320,830
 320,830
Total equity3,697,462
 (250,602) 547,898
 23,534
 4,018,292
Total liabilities and equity$4,688,773
 $3,390,362
 $670,549
 $(3,400,004) $5,349,680


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

See Note 4—Acquisitions and Divestitures for discussion of the fair values of proved oil and natural gas properties assumed in business combinations.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s commodity derivative instruments, interest rate swaps, and investments in the common stock of other entities. The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. The fair values of the Company’s interest rate swaps are determined based on inputs that are readily available in public markets, are determined based on inputs readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs. The fair value of interest rate swaps is recorded as an asset or liability on the consolidated balance sheets. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. The Company has an immaterial investment that is reported at fair value using observable, quoted stock prices and is included in “Other assets” on the Company’s consolidated balance sheet at December 31, 2023.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented under the captions “Derivative instruments” in the Company’s consolidated balance sheets as of December 31, 2023 and December 31, 2022.

As of December 31, 2023
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In millions)
Assets:
Current assets- Derivative instruments:
Commodity derivative instruments$— $88 $— $88 $(71)$17 
Non-current assets- Derivative instruments:
Commodity derivative instruments$— $8 $— $8 $(7)$1 
Non-current assets- Other assets:
Investment$5 $— $— $5 $— $5 
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments$— $111 $— $111 $(71)$40 
Interest rate swaps$— $46 $— $46 $— $46 
Non-current liabilities- Derivative instruments:
Commodity derivative instruments$— $12 $— $12 $(7)$5 
Interest rate swaps$— $117 $— $117 $— $117 

109
Condensed Consolidated Statement of Operations
Year Ended December 31, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $903,842
 $—
 $140,175
 $1,044,017
Natural gas sales—
 42,899
 —
 9,311
 52,210
Natural gas liquid sales—
 79,371
 —
 10,677
 90,048
Royalty income—
 —
 160,163
 (160,163) —
Lease bonus income—
 —
 11,870
 (106) 11,764
Midstream services—
 7,072
 —
 —
 7,072
Total revenues—
 1,033,184
 172,033
 (106) 1,205,111
Costs and expenses:         
Lease operating expenses—
 126,524
 —
 —
 126,524
Production and ad valorem taxes—
 62,897
 10,608
 —
 73,505
Gathering and transportation—
 12,045
 789
 —
 12,834
Midstream services—
 10,409
 —
 —
 10,409
Depreciation, depletion and amortization—
 281,989
 40,519
 4,251
 326,759
General and administrative expenses26,776
 18,057
 6,296
 (2,460) 48,669
Asset retirement obligation accretion—
 1,391
 —
 —
 1,391
Total costs and expenses26,776
 513,312
 58,212
 1,791
 600,091
Income (loss) from operations(26,776) 519,872
 113,821
 (1,897) 605,020
Other income (expense)         
Interest expense, net(29,925) (7,465) (3,164) —
 (40,554)
Other income, net1,142
 10,732
 821
 (2,460) 10,235
Loss on derivative instruments, net—
 (77,512) —
 —
 (77,512)
Total other expense, net(28,783) (74,245) (2,343) (2,460) (107,831)
Income (loss) before income taxes(55,559) 445,627
 111,478
 (4,357) 497,189
Benefit from income taxes(19,568) —
 —
 —
 (19,568)
Net income (loss)(35,991) 445,627
 111,478
 (4,357) 516,757
Net income attributable to non-controlling interest—
 —
 —
 34,496
 34,496
Net income (loss) attributable to Diamondback Energy, Inc.$(35,991) $445,627
 $111,478
 $(38,853) $482,261

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



As of December 31, 2022
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(In millions)
Assets:
Current assets- Derivative instruments:
Commodity derivative instruments$— $197 $— $197 $(65)$132 
Non-current assets- Derivative instruments:
Commodity derivative instruments$— $62 $— $62 $(39)$23 
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments$— $67 $— $67 $(65)$2 
Interest rate swaps$— $45 $— $45 $— $45 
Non-current liabilities- Derivative instruments:
Commodity derivative instruments$— $39 $— $39 $(39)$— 
Interest rate swaps$— $148 $— $148 $— $148 

Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:
December 31, 2023December 31, 2022
CarryingCarrying
ValueFair ValueValueFair Value
(In millions)
Debt$6,641 $6,507 $6,248 $5,754 

The fair values of the Company’s credit agreement and the Viper credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair values of the outstanding notes were determined using the quoted market prices at each period end, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties, equity method investments, asset retirement obligations and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4—Acquisitions and Divestitures and Note 5—Property and Equipment for additional discussion of nonrecurring fair value adjustments.

Fair Value of Financial Assets

The carrying amount of cash and cash equivalents, receivables, prepaid expenses, other current assets, payables and other accrued liabilities and funds held in escrow approximate their fair value because of the short-term nature of the instruments.

110
Condensed Consolidated Statement of Operations
Year Ended December 31, 2016
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $399,007
 $—
 $71,521
 $470,528
Natural gas sales—
 19,399
 —
 3,107
 22,506
Natural gas liquid sales—
 29,864
 —
 4,209
 34,073
Royalty income—
 —
 78,837
 (78,837) —
Lease bonus income—
 —
 309
 (309) —
Total revenues—
 448,270
 79,146
 (309) 527,107
Costs and expenses:         
Lease operating expenses—
 82,428
 —
 —
 82,428
Production and ad valorem taxes—
 28,912
 5,544
 —
 34,456
Gathering and transportation—
 11,189
 415
 2
 11,606
Depreciation, depletion and amortization—
 151,376
 29,820
 (3,181) 178,015
Impairment of oil and natural gas properties—
 198,067
 47,469
 —
 245,536
General and administrative expenses25,959
 11,451
 5,209
 —
 42,619
Asset retirement obligation accretion—
 1,064
 —
 —
 1,064
Total costs and expenses25,959
 484,487
 88,457
 (3,179) 595,724
Income (loss) from operations(25,959) (36,217) (9,311) 2,870
 (68,617)
Other income (expense)         
Interest expense, net(35,318) (2,911) (2,455) —
 (40,684)
Other income, net437
 2,010
 867
 (250) 3,064
Loss on derivative instruments, net—
 (25,345) —
 —
 (25,345)
Loss on extinguishment of debt(33,134) —
 —
 —
 (33,134)
Total other expense, net(68,015) (26,246) (1,588) (250) (96,099)
Income (loss) before income taxes(93,974) (62,463) (10,899) 2,620
 (164,716)
Provision for income taxes192
 —
 —
 —
 192
Net income (loss)(94,166) (62,463) (10,899) 2,620
 (164,908)
Net income attributable to non-controlling interest—
 —
 —
 126
 126
Net income (loss) attributable to Diamondback Energy, Inc.$(94,166) $(62,463) $(10,899) $2,494
 $(165,034)

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



14.    SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS

Year Ended December 31,
202320222021
(In millions)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest$(146)$(135)$(194)
Cash (paid) received for income taxes, net$(352)$(718)$138 
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses$618 $520 $287 
Capitalized stock-based compensation$26 $21 $20 
Common stock issued for acquisitions$633 $1,220 $1,727 
Assets contributed in exchange for ownership interest in an equity method investment$126 $— $— 
Asset retirement obligations acquired$8 $19 $65 

15.    COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings, disputes or claims and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records accrued liabilities for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Commitments

The following is a schedule of minimum future payments with commitments that have initial or remaining noncancellable terms in excess of one year as of December 31, 2023:
Year Ending December 31,
Transportation Commitments(1)
Electrical Fracturing Fleet(2)
Sand Supply Agreement(3)
Produced Water Disposal Commitments(4)
Electrical Power Agreements(5)
(In millions)
2024$98 $50 $26 $5 $72 
2025103 40 22 3 72 
2026109 3 18 4 71 
202777 — 4 4 70 
202867 — — 3 37 
Thereafter314 — — 21 85 
Total$768 $93 $70 $40 $407 
(1)The Company has committed to transport gross quantities of crude oil and natural gas on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above.
111
Condensed Consolidated Statement of Operations
Year Ended December 31, 2015
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $336,106
 $—
 $69,609
 $405,715
Natural gas sales—
 16,932
 —
 2,660
 19,592
Natural gas liquid sales—
 18,836
 —
 2,590
 21,426
Royalty income—
 —
 74,859
 (74,859) —
Total revenues—
 371,874
 74,859
 —
 446,733
Costs and expenses:         
Lease operating expenses—
 82,625
 —
 —
 82,625
Production and ad valorem taxes—
 27,459
 5,531
 —
 32,990
Gathering and transportation—
 5,832
 259
 —
 6,091
Depreciation, depletion and amortization—
 182,395
 35,436
 (134) 217,697
Impairment of oil and natural gas properties—
 814,798
 3,423
 (3,423) 814,798
General and administrative expenses17,077
 9,056
 5,835
 —
 31,968
Asset retirement obligation accretion expense—
 833
 —
 —
 833
Total costs and expenses17,077
 1,122,998
 50,484
 (3,557) 1,187,002
Income (loss) from operations(17,077) (751,124) 24,375
 3,557
 (740,269)
Other income (expense)         
Interest expense, net(35,651) (4,749) (1,110) —
 (41,510)
Other income, net1
 (427) 1,154
 —
 728
Gain on derivative instruments, net—
 31,951
 —
 —
 31,951
Total other expense, net(35,650) 26,775
 44
 —
 (8,831)
Income (loss) before income taxes(52,727) (724,349) 24,419
 3,557
 (749,100)
Benefit from income taxes(201,310) —
 —
 —
 (201,310)
Net income (loss)$148,583
 $(724,349) $24,419
 $3,557
 $(547,790)
Net income attributable to non-controlling interest$—
 $—
 $—
 $2,838
 $2,838
Net income (loss) attributable to Diamondback Energy, Inc.$148,583
 $(724,349) $24,419
 $719
 $(550,628)



F-40


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



(2)In 2022, the Company entered into commitments for three years for the Company’s electric fracturing fleet and related power generating services.
(3)The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above.
(4)The Company has a minimum volume commitment to purchase produced water disposal services under a 14 year agreement which began in 2021.
(5)The Company has fixed price contracts with various suppliers for the purchase of electrical power through 2032.

At December 31, 2023, the Company’s delivery commitments covered the following gross volumes of oil:

Year Ending December 31,Oil Volume Commitments (Bbl/d)
2024175,000
2025175,000
2026150,000
2027150,000
202850,000
Thereafter50,000
Total750,000

See Note 4—Acquisitions and Divestitures for further details on commitments acquired during the Deep Blue transaction.

Environmental Matters

The United States Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including a corporate predecessor of Energen Corporation, to perform decommissioning and reclamation activities related to a Louisiana offshore oil and gas production platform and related facilities. In response to the insolvency of the operator of record, the government ordered the former operators and/or alleged former lease record title owners to decommission the platform and related facilities. The Company has agreed to an arrangement with other operators to contribute to a trust to fund the decommissioning costs, however, the Company’s portion of such costs are not expected to be material.

Beginning in 2013 and continuing through the fourth quarter of 2023, several coastal Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local Coastal Resources Management Act (“SLCRMA”) against numerous oil and gas producers seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone. The Company is a defendant in three of these cases, and Plaintiffs’ claims against the Company relate to the prior operations of entities previously acquired by Energen Corporation. The Company has exercised contractual indemnification rights where applicable. Plaintiffs’ SLCRMA theories are unprecedented, and there remains significant uncertainty about the claims (both as to scope and damages). Although we cannot predict the ultimate outcome of these matters, the Company believes the claims lack merit and intends to continue vigorously defending these lawsuits.

16.    SUBSEQUENT EVENTS

Fourth Quarter 2023 Dividend Declaration

On February 11, 2024, the board of directors of the Company approved an increase in the Company’s annual base dividend to $3.60 per share of common stock and, on February 16, 2024, the board of directors of the Company declared a cash dividend for the fourth quarter of 2023 of $3.08 per share of common stock, payable on March 12, 2024 to its stockholders of record at the close of business on March 5, 2024. The dividend consists of a base quarterly dividend of $0.90 per share of common stock and a variable quarterly dividend of $2.18 per share of common stock. Future base and variable dividends are at the discretion of the board of directors of the Company.

Beginning in the first quarter of 2024, the Company will reduce its return of capital commitment to at least 50% from 75% of its quarterly free cash flow.
112
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2017
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by (used in) operating activities$(29,470) $778,876
 $139,219
 $—
 $888,625
Cash flows from investing activities:         
Additions to oil and natural gas properties—
 (792,599) —
 —
 (792,599)
Additions to midstream assets—
 (68,139) —
 —
 (68,139)
Purchase of other property, equipment and land—
 (22,779) —
 —
 (22,779)
Acquisition of leasehold interests—
 (1,960,591) —
 —
 (1,960,591)
Acquisition of mineral interests—
 (63,371) (344,079) —
 (407,450)
Acquisition of midstream assets—
 (50,279) —
 —
 (50,279)
Proceeds from sale of assets—
 65,656
 —
 —
 65,656
Funds held in escrow—
 104,087
 —
 —
 104,087
Equity investments—
 (188) —
 —
 (188)
Intercompany transfers(1,631,078) 1,631,078
 —
 —
 —
Net cash used in investing activities(1,631,078) (1,157,125) (344,079) —
 (3,132,282)
Cash flows from financing activities:         
Proceeds from borrowing on credit facility—
 475,000
 278,500
 —
 753,500
Repayment on credit facility—
 (78,000) (305,500) —
 (383,500)
Purchase of subsidiary units by parent(10,068) —
 —
 10,068
 —
Debt issuance costs(8,326) 1,289
 (2,259) —
 (9,296)
Public offering costs(77) —
 (433) —
 (510)
Proceeds from public offerings—
 —
 380,412
 (10,068) 370,344
Distribution from subsidiary89,509
 —
 —
 (89,509) —
Exercise of stock options358
 —
 —
 —
 358
Distribution to non-controlling interest—
 —
 (130,876) 89,509
 (41,367)
Net cash provided by financing activities71,396
 398,289
 219,844
 —
 689,529
Net increase (decrease) in cash and cash equivalents(1,589,152) 20,040
 14,984
 —
 (1,554,128)
Cash and cash equivalents at beginning of period1,643,226
 14,135
 9,213
 —
 1,666,574
Cash and cash equivalents at end of period$54,074
 $34,175
 $24,197
 $—
 $112,446

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Pending Endeavor Acquisition

On February 11, 2024, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”), by and among the Company, Eclipse Merger Sub I, LLC, Eclipse Merger Sub II, LLC, Endeavor Manager, LLC (solely for purposes of certain sections set forth therein), and Endeavor Parent, LLC (“Endeavor”), to acquire Endeavor (such acquisition, the “Endeavor Acquisition”) for consideration consisting of a base cash amount of $8.0 billion, subject to adjustments under the terms of the Merger Agreement, and approximately 117.27 million shares of the Company’s common stock. The Endeavor Acquisition is expected to close in the fourth quarter of 2024, subject to the satisfaction or waiver of certain customary closing conditions, including the approval of the issuance of the Company’s common stock in the Endeavor Acquisition by the Company’s stockholders and the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. As a result of the Endeavor Acquisition, equityholders of Endeavor are expected to hold, at closing, approximately 39.5% of the outstanding Company common stock. If the Merger Agreement is terminated under certain circumstances, the Company may be required to pay a termination fee of $1.4 billion, including if the proposed Merger Agreement is terminated because the Company’s board of directors has changed its recommendation in respect of the stockholder proposal relating to approval of the issuance of the Company common stock in the Endeavor Acquisition. Additionally, if the Merger Agreement is terminated because the Company’s stockholders fail to approve the issuance of the Company’s common stock in the Endeavor Acquisition and the termination fee is not payable in connection with such termination, the Company is required to reimburse Endeavor for its transaction related expenses, subject to a cap of $260 million. The payment of this reimbursement will reduce any termination fee that is subsequently payable by the Company.

On February 11, 2024, in connection with the execution of the Merger Agreement, the Company entered into a commitment letter with Citigroup Global Markets Inc. (“Citi”) pursuant to which Citi committed to provide an $8.0 billion senior unsecured bridge facility, subject to customary conditions. The Company expects to replace such commitment with permanent debt financing prior to the closing of the Endeavor Acquisition.

17.    SEGMENT INFORMATION

The Company reports its operations in one reportable segment: the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. Other operations are included in the “All Other” category in the table below. The sources of the revenue included in the “All Other” category include midstream gathering, compression, water handling, disposal and treatment operations which are primarily derived from intersegment transactions for services provided to the upstream segment. The segments comprise the structure used by the Company’s Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance.

113
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2016
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by (used in) operating activities$(39,894) $303,347
 $68,627
 $—
 $332,080
Cash flows from investing activities:         
Additions to oil and natural gas properties—
 (363,087) —
 —
 (363,087)
Additions to midstream assets—
 (1,188) —
 —
 (1,188)
Purchase of other property, equipment and land—
 (9,891) —
 —
 (9,891)
Acquisition of leasehold interests—
 (611,280) —
 —
 (611,280)
Acquisition of mineral interests—
 —
 (205,721) —
 (205,721)
Proceeds from sale of assets—
 4,661
 —
 —
 4,661
Funds held in escrow—
 (121,391) —
 —
 (121,391)
Equity investments—
 (2,345) —
 —
 (2,345)
Intercompany transfers(796,053) 796,053
 —
 —
 —
Net cash used in investing activities(796,053) (308,468) (205,721) —
 (1,310,242)
Cash flows from financing activities:         
Proceeds from borrowing on credit facility—
 —
 164,000
 —
 164,000
Repayment on credit facility—
 (11,000) (78,000) —
 (89,000)
Proceeds from senior notes1,000,000
 —
 —
 —
 1,000,000
Repayment of senior notes(450,000) —
 —
 —
 (450,000)
Premium on extinguishment of debt(26,561) —
 —
 —
 (26,561)
Debt issuance costs(14,449) (172) (442) —
 (15,063)
Public offering costs(636) —
 (546) —
 (1,182)
Proceeds from public offerings1,925,923
 —
 125,580
 —
 2,051,503
Distribution from subsidiary55,250
 —
 —
 (55,250) —
Exercise of stock options498
 —
 —
 —
 498
Distribution to non-controlling interest—
 —
 (64,824) 55,250
 (9,574)
Intercompany transfers(11,000) 11,000
 —
 —
 —
Net cash provided by (used in) financing activities2,479,025
 (172) 145,768
 —
 2,624,621
Net increase (decrease) in cash and cash equivalents1,643,078
 (5,293) 8,674
 —
 1,646,459
Cash and cash equivalents at beginning of period148
 19,428
 539
 —
 20,115
Cash and cash equivalents at end of period$1,643,226
 $14,135
 $9,213
 $—
 $1,666,574

F-42


Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



The following tables summarize the results of the Company's operating segments during the periods presented:

UpstreamAll OtherEliminationsTotal
(In millions)
Year Ended December 31, 2023:
Third-party revenues$8,344 $68 $— $8,412 
Intersegment revenues— 329 (329)— 
Total revenues$8,344 $397 $(329)$8,412 
Depreciation, depletion, amortization and accretion$1,707 $39 $— $1,746 
Income (loss) from operations$4,519 $129 $(78)$4,570 
Interest expense, net$(176)$1 $— $(175)
Other income (expense)$(268)$88 $(15)$(195)
Income (loss) from equity investments$(1)$49 $— $48 
Provision for (benefit from) income taxes$888 $24 $— $912 
Net income (loss) attributable to non-controlling interest$193 $— $— $193 
Net income (loss) attributable to Diamondback Energy, Inc.$2,993 $243 $(93)$3,143 
Total assets$28,362 $1,242 $(603)$29,001 
UpstreamAll OtherEliminationsTotal
(In millions)
Year Ended December 31, 2022:
Third-party revenues$9,572 $71 $— $9,643 
Intersegment revenues— 369 (369)— 
Total revenues$9,572 $440 $(369)$9,643 
Depreciation, depletion, amortization and accretion$1,279 $65 $— $1,344 
Income (loss) from operations$6,432 $166 $(90)$6,508 
Interest expense, net$(130)$(29)$— $(159)
Other income (expense)$(653)$(21)$(16)$(690)
Income (loss) from equity investments$— $77 $— $77 
Provision for (benefit from) income taxes$1,165 $9 $— $1,174 
Net income (loss) attributable to non-controlling interest$150 $26 $— $176 
Net income (loss) attributable to Diamondback Energy, Inc.$4,334 $158 $(106)$4,386 
Total assets$24,452 $2,213 $(456)$26,209 

114
Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2015
(In thousands)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by (used in) operating activities$(37,597) $390,266
 $63,832
 $—
 $416,501
Cash flows from investing activities:         
Additions to oil and natural gas properties—
 (419,512) —
 —
 (419,512)
Purchase of other property, equipment and land—
 (1,213) —
 —
 (1,213)
Acquisition of leasehold interests—
 (437,455) —
 —
 (437,455)
Acquisition of royalty interests—
 —
 (43,907) —
 (43,907)
Proceeds from sale of assets—
 9,739
 —
 —
 9,739
Equity investments—
 (2,702) —
 —
 (2,702)
Intercompany transfers(145,023) 145,023
 —
 —
 —
Net cash used in investing activities(145,023) (706,120) (43,907) —
 (895,050)
Cash flows from financing activities:         
Proceeds from borrowing on credit facility—
 390,501
 34,500
 —
 425,001
Repayment on credit facility—
 (603,001) —
 —
 (603,001)
Debt issuance costs—
 (85) (441) —
 (526)
Public offering costs(586) —
 —
 —
 (586)
Proceeds from public offerings650,688
 —
 —
 —
 650,688
Distribution from subsidiary60,587
 —
 —
 (60,587) —
Exercise of stock options4,873
 —
 —
 —
 4,873
Distribution to non-controlling interest—
 —
 (68,555) 60,587
 (7,968)
Intercompany transfers(532,800) 532,800
 —
 —
 —
Net cash provided by (used in) financing activities182,762
 320,215
 (34,496) —
 468,481
Net increase (decrease) in cash and cash equivalents142
 4,361
 (14,571) —
 (10,068)
Cash and cash equivalents at beginning of period6
 15,067
 15,110
 —
 30,183
Cash and cash equivalents at end of period$148
 $19,428
 $539
 $—
 $20,115


F-43


Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



UpstreamAll OtherEliminationsTotal
(In millions)
Year Ended December 31, 2021:
Third-party revenues$6,747 $50 $— $6,797 
Intersegment revenues— 371 (371)— 
Total revenues$6,747 $421 $(371)$6,797 
Depreciation, depletion, amortization and accretion$1,219 $56 $— $1,275 
Income (loss) from operations$3,879 $180 $(58)$4,001 
Interest expense, net$(167)$(32)$— $(199)
Other income (expense)$(925)$23 $(8)$(910)
Income (loss) from equity investments$— $15 $— $15 
Provision for (benefit from) income taxes$620 $11 $— $631 
Net income (loss) attributable to non-controlling interest$57 $37 $— $94 
Net income (loss) attributable to Diamondback Energy, Inc.$2,110 $138 $(66)$2,182 
Total assets$21,329 $1,942 $(373)$22,898 

18. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)(UNAUDITED)


The Company’s oil and natural gas reserves are attributable solely to properties within the United States.


Capitalized oil and natural gas costs


Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
December 31,
20232022
(In millions)
Oil and natural gas properties:
Proved properties$33,771 $28,767 
Unproved properties8,659 8,355 
Total oil and natural gas properties42,430 37,122 
Accumulated depletion(8,333)(6,671)
Accumulated impairment(7,954)(7,954)
Net oil and natural gas properties capitalized$26,143 $22,497 
 December 31,
 2017 2016
 (In thousands)
Oil and Natural Gas Properties:   
Proved properties$5,126,829
 $3,429,742
Unproved properties4,105,865
 1,730,519
Total oil and natural gas properties9,232,694
 5,160,261
Accumulated depreciation, depletion, amortization(1,009,893) (687,685)
Accumulated impairment(1,143,498) (1,143,498)
Net oil and natural gas properties capitalized$7,079,303
 $3,329,078


Costs incurred in oil and natural gas activities


Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
Year Ended December 31,
202320222021
(In millions)
Acquisition costs:
Proved properties$1,314 $778 $2,805 
Unproved properties1,701 1,536 1,829 
Development costs1,962 566 516 
Exploration costs768 1,698 1,223 
Total$5,745 $4,578 $6,373 
 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Acquisition costs     
Proved properties$452,661
 $72,044
 $64,340
Unproved properties2,692,000
 752,117
 448,638
Development costs145,362
 47,575
 42,749
Exploration costs779,728
 329,122
 319,102
Capitalized asset retirement costs2,682
 4,030
 3,458
Total$4,072,433
 $1,204,888
 $878,287



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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Results of Operations from Oil and Natural Gas Producing Activities


The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas.gas liquids. It does not include any interest costs or general and administrative costs. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and therefore,amortization and accretion and impairment. Therefore, the following schedule is not necessarily indicative of the contribution to consolidatedthe net operating results of ourthe Company’s oil, natural gas and natural gas liquids operations.

 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Oil, natural gas and natural gas liquid sales$1,186,275
 $527,107
 $446,733
Lease operating expenses(126,524) (82,428) (82,625)
Production and ad valorem taxes(73,505) (34,456) (32,990)
Gathering and transportation(12,834) (11,606) (6,091)
Depreciation, depletion, and amortization(321,870) (176,369) (216,056)
Impairment—
 (245,536) (814,798)
Asset retirement obligation accretion expense(1,391) (1,064) (833)
Income tax benefit (expense)19,568
 (192) 201,310
Results of operations$669,719
 $(24,544) $(505,350)
Year Ended December 31,
202320222021
(In millions)
Oil, natural gas and natural gas liquid sales$8,228 $9,566 $6,747 
Production costs(1,684)(1,521)(1,202)
Depreciation, depletion, amortization and accretion(1,684)(1,264)(1,211)
Income tax benefit (expense)(1,000)(1,437)(918)
Results of operations$3,860 $5,344 $3,416 


Oil and Natural Gas Reserves


Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2017, 20162023 and 2015 were2022 and prepared by Ryder Scott Company, L.P., independent petroleum engineers.as of December 31, 2021. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon SEC Prices for the 12-month unweighted averageperiods ending December 31, 2023, 2022 and 2021, respectively. 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 the net revenue interest in the Company’s properties, all of which are located within the first-day-of-the-month prices.continental United States. Although the Company believes 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.


There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.



The following table presents changes in the Company’s estimated proved reserves (including those attributable to Viper). As of December 31, 2023, none of the Company’s total proved reserves were classified as proved developed non-producing.
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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



Oil
(MBbls)		Natural Gas
 (MMcf)		Natural Gas
Liquids
(MBbls)
Total
(MBOE)(1)
Proved Developed and Undeveloped Reserves:
As of December 31, 2020759,401 1,607,064 289,196 1,316,441 
Extensions and discoveries271,222 720,125 127,479 518,722 
Revisions of previous estimates(160,570)195,302 (6,685)(134,705)
Purchase of reserves in place176,261 302,770 58,587 285,310 
Divestitures(36,503)(70,048)(11,597)(59,775)
Production(81,522)(169,406)(27,246)(137,002)
As of December 31, 2021928,289 2,585,807 429,734 1,788,991 
Extensions and discoveries201,326 386,987 68,671 334,495 
Revisions of previous estimates(10,483)2,827 3,228 (6,784)
Purchase of reserves in place38,683 82,287 15,645 68,043 
Divestitures(6,691)(12,671)(2,079)(10,882)
Production(81,616)(176,376)(29,880)(140,892)
As of December 31, 20221,069,508 2,868,861 485,319 2,032,971 
Extensions and discoveries206,562 424,881 78,498 355,874 
Revisions of previous estimates(56,482)(47,697)9,962 (54,470)
Purchase of reserves in place41,790 79,507 15,440 70,481 
Divestitures(21,258)(130,013)(20,755)(63,682)
Production(96,176)(198,117)(34,217)(163,413)
As of December 31, 20231,143,944 2,997,422 534,247 2,177,761 
Proved Developed Reserves:
December 31, 2020443,464 1,085,035 192,495 816,798 
December 31, 2021620,474 1,770,688 285,513 1,201,102 
December 31, 2022699,513 2,122,782 350,243 1,403,553 
December 31, 2023744,103 2,203,563 385,167 1,496,530 
Proved Undeveloped Reserves:
December 31, 2020315,937 522,029 96,701 499,643 
December 31, 2021307,815 815,119 144,221 587,889 
December 31, 2022369,995 746,079 135,076 629,418 
December 31, 2023399,841 793,859 149,080 681,231 
The changes in estimated(1) Includes total proved reserves areof 78,870 MBOE, 65,516 MBOE, 58,828 MBOE and 41,745 MBOE as follows:of December 31, 2023, 2022, 2021 and 2020, respectively, attributable to a non-controlling interest in Viper.
 Oil
(MBbls)		 Natural Gas
Liquids
(MBbls)		 Natural Gas
(MMcf)
Proved Developed and Undeveloped Reserves:     
As of January 1, 201575,690
 18,542
 111,605
Extensions and discoveries48,725
 12,056
 53,453
Revisions of previous estimates(12,130) (4,081) (14,726)
Purchase of reserves in place2,775
 1,165
 7,102
Production(9,081) (1,678) (7,931)
As of December 31, 2015105,979
 26,004
 149,503
Extensions and discoveries55,069
 13,962
 64,758
Revisions of previous estimates(12,483) (1,888) (34,519)
Purchase of reserves in place2,537
 1,455
 7,567
Divestitures(366) —
 (1,985)
Production(11,562) (2,399) (10,428)
As of December 31, 2016139,174
 37,134
 174,896
Extensions and discoveries99,980
 20,825
 109,032
Revisions of previous estimates(7,715) (1,466) (10,065)
Purchase of reserves in place24,322
 2,633
 34,640
Divestitures(1,163) (461) (2,474)
Production(21,417) (4,056) (20,660)
As of December 31, 2017233,181
 54,609
 285,369
      
Proved Developed Reserves:     
January 1, 201543,886
 11,221
 68,264
December 31, 201560,569
 15,418
 96,871
December 31, 201679,457
 22,080
 105,399
December 31, 2017141,246
 35,412
 190,740
      
Proved Undeveloped Reserves:     
January 1, 201531,804
 7,321
 43,341
December 31, 201545,409
 10,586
 52,632
December 31, 201659,717
 15,054
 69,497
December 31, 201791,935
 19,198
 94,629


Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.


During the year ended December 31, 2017,2023, the Company’s extensions and discoveries of 138,977355,874 MBOE resulted primarily from the drilling of 102954 new wells in which the Company has an interest, including 826 wells in which the Company owns only a mineral interest through Viper, and from 87344 new proved undeveloped locations added. PartnershipViper royalty interests accounted for 8%7% of the extension volumes. The Company’s downward revisions of previous estimates of 54,470 MBOE were primarily the result of 2,550 MBOE from reclassifying PUD locations dueattributable to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59 new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 of the 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates(i) 62,370 MBOE associated with lower commodity prices and (ii) 32,249 MBOE due to PUD downgrades related to changes in the corporate development plan. These were primarilypartially offset by positive revisions of 40,149 MBOE due to improved performance. Purchases of 70,481 MBOE consisted of 54,470 MBOE attributable largely to the result of 5,978Lario Acquisition and 16,011 MBOE of pricing revisions and 7,253Viper royalty purchases. Divestitures of 63,682 MBOE from reclassifying 17 locations from proved undeveloped duerelated primarily to pricing. Purchases of reserves in place of 3,993 MBOEnon-core Midland Basin assets.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated with multiple purchases made by the Partnership.

During the year ended December 31, 2015,2022, the Company made one large acquisitionCompany’s extensions and discoveries of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitions were334,495 MBOE resulted primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the timedrilling of acquisition. Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal654 new wells in which the Company has a working interest, and from 16 horizontalincluding 576 wells in which the Company haswe own only a mineral interest through its ownership in Viper. Of the two vertical wellsViper, and 135 horizontal wells, onefrom 311 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the vertical wells and 89extension volumes. The Company’s downward revisions of the horizontal wells are in the proved undeveloped category. The revisions are primarilyprevious estimates of 6,784 MBOE were the result of lower product pricing. As a resultnegative revisions of lower pricing, 80 vertical wells98,902 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the FireBird Acquisition, partially offset with positive revisions of 92,118 MBOE associated with higher commodity prices. Purchases of 68,043 MBOE consisted of 67,037 MBOE attributable largely to the FireBird Acquisition and 22 horizontal1,005 MBOE of Viper royalty purchases. Divestitures of 10,882 MBOE related primarily to non-core Delaware Basin assets and the Eagle Ford Basin Divestiture.

During the year ended December 31, 2021, the Company’s extensions and discoveries of 518,722 MBOE resulted primarily from the drilling of 470 new wells in which the Company has a working interest, and 22 verticalincluding 345 wells in which the Company haswe own only a mineral interest were downgradedthrough Viper, and from the439 new proved undeveloped category to probable or possible reserves. Additionallocations added. Viper royalty interests accounted for 6% of the extension volumes. The Company’s downward revisions of previous estimates of 134,705 MBOE were the result of negative revisions of 268,560 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 133,855 MBOE associated with higher commodity prices and improved well performance. Purchases of 285,309 MBOE primarily resulted from shorter producing lives on existing wells as a result276,207 MBOE attributable largely to the QEP Merger and Guidon Acquisition, and 9,102 MBOE of Viper royalty purchases, including the wells reaching their economic limit sooner dueSwallowtail Acquisition. Divestitures of 59,775 MBOE related primarily to lower revenues.the Williston Basin Divestiture.


Proved Undeveloped Reserves (PUDs)

At December 31, 2017,2023, the Company’s estimated PUD reserves were approximately 126,904681,231 MBOE, a 40,55051,813 MBOE increase over the reserve estimate at December 31, 20162022 of 86,354629,418 MBOE. The following table includes the changes in PUD reserves for 2017:2023 (MBOE):


(MBOE)
Beginning proved undeveloped reserves at December 31, 2016202286,354629,418 
Undeveloped reserves transferred to developed(31,666(187,097))
Revisions(4,710(34,110))
Net purchasesPurchases6,2464,206 
Divestitures(7,461)
Extensions and discoveries70,680276,275 
Ending proved undeveloped reserves at December 31, 20172023126,904681,231 


The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676266,178 MBOE from 87344 gross (75(295 net) wells in which the Company has a working interest and 3,00410,097 MBOE from 40179 gross wells in which the PartnershipViper owns royalty interests. Of the 87344 gross working interest wells, 26321 were in the Midland Basin and 23 were in the Delaware Basin. Transfers of 31,666187,097 MBOE from undeveloped to developed reserves were the result of drilling or participating in 44204 gross (37(184 net) horizontal wells in which the Company has a working interest and 27170 gross wells in which the Company also has a royalty interest or mineral interest through the Partnership. The Company owns a working interest in 23Viper. Downward revisions of the 27 gross Partnership wells. Net purchases of 6,24634,110 MBOE were primarily the result of negative revisions of 25,893 MBOE due to downgrades related to changes in the corporate development plan, and negative revisions of 8,217 MBOE attributable to lower commodity prices. Purchases of 4,206 MBOE consisted of 3,288 MBOE primarily from insignificant trades and acquisitions and 918 MBOE from the Company’s purchase in PecosGRP Acquisition and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.other insignificant royalty interest purchases.


As of December 31, 2017, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2017,2023, approximately $145.4 million$2.0 billion in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Estimated future development costs relating to the development of PUDs are projected to be approximately $1.6 billion in 2024, $1.4 billion in 2025, $930 million in 2026 and $676 million in 2027. 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.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

With our current development plan, we expect to continue our strong PUD conversion ratio in 2024 by converting an estimated 38% of our PUDs to a proved developed category and developing approximately 83% of the consolidated 2023 year-end PUD reserves by the end of 2026. As of December 31, 2023, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

Standardized Measure of Discounted Future Net Cash Flows


The standardized measure of discounted future net cash flows is based on the unweighted arithmetic average, first-day-of-the-month price.price for the rolling 12-month period. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.


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Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)



The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2017, 20162023, 2022 and 2015.2021:
December 31,
202320222021
(In millions)
Future cash inflows$106,418 $137,051 $77,085 
Future development costs(1)
(6,400)(6,176)(4,243)
Future production costs(25,656)(25,295)(19,123)
Future production taxes(7,434)(9,927)(5,572)
Future income tax expenses(11,067)(17,563)(7,237)
Future net cash flows55,861 78,090 40,910 
10% discount to reflect timing of cash flows(28,803)(42,391)(22,193)
Standardized measure of discounted future net cash flows(2)
$27,058 $35,699 $18,717 
 December 31,
 2017 2016 2015
 (In thousands)
Future cash inflows$12,921,897
 $6,275,705
 $5,377,783
Future development costs(1,123,979) (617,636) (548,239)
Future production costs(2,994,877) (1,392,852) (1,279,101)
Future production taxes(928,891) (459,244) (363,129)
Future income tax expenses(83,961) (75,595) (28,233)
Future net cash flows7,790,189
 3,730,378
 3,159,081
10% discount to reflect timing of cash flows(4,033,130) (2,018,965) (1,740,948)
Standardized measure of discounted future net cash flows$3,757,059
 $1,711,413
 $1,418,133
(1) Includes approximately $685 million, $756 million, and $339 million of undiscounted future asset retirement costs for the years ended December 31, 2023, 2022 and 2021, respectively, based on estimates made at the end of each of the respective years,

(2)    Includes $3.2 billion, $3.5 billion and $2.1 billion, for the years ended December 31, 2023, 2022 and 2021, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 44%, 44% and 46% non-controlling interest at December 31, 2023 2022 and 2021, respectively.
In the
The table below presents the average first-day-of–the-month priceSEC Prices as adjusted for oil, natural gasdifferentials and natural gas liquids is presented, allcontractual arrangements utilized in the computation of future cash inflows.inflows:
December 31,
202320222021
Oil (per Bbl)$77.62 $95.26 $64.78 
Natural gas (per Mcf)$1.53 $5.59 $2.61 
Natural gas liquids (per Bbl)$24.40 $39.40 $23.71 

119
 December 31,
 2017 2016 2015
 Unweighted Arithmetic Average
 First-Day-of-the-Month Prices
Oil (per Bbl)$48.03
 $39.94
 $45.07
Natural gas (per Mcf)$2.06
 $1.36
 $1.83
Natural gas liquids (per Bbl)$20.79
 $12.91
 $12.56

Diamondback Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements-(Continued)

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:
Year Ended December 31,
202320222021
(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period$35,699 $18,717 $6,758 
Sales of oil and natural gas, net of production costs(6,544)(8,045)(5,757)
Acquisitions of reserves1,854 1,473 1,914 
Divestitures of reserves(938)(119)(275)
Extensions and discoveries, net of future development costs5,771 7,674 6,298 
Previously estimated development costs incurred during the period1,180 823 548 
Net changes in prices and production costs(17,276)17,785 10,748 
Changes in estimated future development costs518 (317)(19)
Revisions of previous quantity estimates(1,268)102 719 
Accretion of discount4,533 2,183 703 
Net change in income taxes2,506 (4,904)(2,841)
Net changes in timing of production and other1,023 327 (79)
Standardized measure of discounted future net cash flows at the end of the period$27,058 $35,699 $18,717 

120
 Year Ended December 31,
 2017 2016 2015
 (In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period$1,711,413
 $1,418,133
 $2,045,224
Sales of oil and natural gas, net of production costs(986,246) (411,558) (331,119)
Acquisition of reserves439,396
 43,142
 58,849
Divestiture of reserves(11,072) (5,481) (1,490)
Extensions and discoveries, net of future development costs1,791,686
 779,359
 629,149
Previously estimated development costs incurred during the period190,121
 85,696
 129,901
Net changes in prices and production costs577,781
 (150,509) (1,383,698)
Changes in estimated future development costs(52,908) 20,647
 38,638
Revisions of previous quantity estimates(98,857) (123,795) (377,160)
Accretion of discount174,185
 143,134
 236,716
Net change in income taxes(9,074) (30,530) 268,963
Net changes in timing of production and other30,634
 (56,825) 104,160
Standardized measure of discounted future net cash flows at the end of the period$3,757,059
 $1,711,413
 $1,418,133
Table of Contents

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE


None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2023, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2023, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of our Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internal control over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2023.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31, 2023. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31, 2023, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors and Stockholders
Diamondback Energy, Inc.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and Subsidiariessubsidiaries (the “Company”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
Notes to Consolidated Financial Statements-(Continued)

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2023, and our report dated February 22, 2024 expressed an unqualified opinion on those financial statements.


19. QUARTERLY FINANCIAL DATA (Unaudited)Basis for opinion


The Company’s unaudited quarterlymanagement is responsible for maintaining effective internal control over financial datareporting and for 2017its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and 2016are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is summarized below.a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
February 22, 2024
122
 2017
 First
Quarter		 Second
Quarter		 Third
Quarter		 Fourth
Quarter
Revenues$235,230
 $269,434
 $301,253
 $399,194
Income from operations116,410
 132,308
 142,639
 213,663
Income tax expense (benefit)1,957
 1,579
 857
 (23,961)
Net income141,074
 164,128
 81,948
 129,607
Net income attributable to non-controlling interest4,801
 5,723
 8,924
 15,048
Net income attributable to Diamondback Energy, Inc.$136,273
 $158,405
 $73,024
 $114,559
Earnings per common share       
Basic$1.46
 $1.61
 $0.74
 $1.17
Diluted$1.46
 $1.61
 $0.74
 $1.16
        
 2016
 First
Quarter		 Second
Quarter		 Third
Quarter		 Fourth
Quarter
Revenues$87,481
 $112,483
 $142,131
 $185,012
Income (loss) from operations(27,603) (134,786) 6,693
 87,079
Income tax expense (benefit)—
 368
 —
 (176)
Net income (loss)(35,627) (157,121) (600) 28,440
Net income (loss) attributable to non-controlling interest(2,715) (1,631) 1,630
 2,842
Net income (loss) attributable to Diamondback Energy, Inc.$(32,912) $(155,490) $(2,230) $25,598
Earnings per common share       
Basic$(0.46) $(2.17) $(0.03) $0.32
Diluted$(0.46) $(2.17) $(0.03) $0.32

ITEM 9B. OTHER INFORMATION



None of the Company’s directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended December 31, 2023.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2023.

We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accounting officer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosed on our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Investors—Corporate Governance” section at https://www.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, a provision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.

ITEM 11. EXECUTIVE COMPENSATION

Information as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2023.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2023.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2023.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2023.

F-49
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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
3. Exhibits
Exhibit NumberDescription
2.1#
Agreement and Plan of Merger, dated as of December 20, 2020, by and among Diamondback Energy, Inc., Bohemia Merger Sub, Inc. and QEP Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2020).
2.2#
Agreement and Plan of Merger, dated as of May 15, 2022, by and among Diamondback Energy, Inc., Rattler Midstream GP LLC, Bacchus Merger Sub Company and Rattler Midstream LP (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on May 16, 2022).
2.3#
Agreement and Plan of Merger, dated as of February 11, 2024, by and among the Company, Endeavor, Merger Sub I, Merger Sub II and the Company Representative (for purposes of certain sections set forth therein) (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on February 12, 2024).
3.1
Second Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 14, 2023).
3.2
Fourth Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 14, 2023).
4.1*
Description of the Company’s Securities.
4.2
Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
4.3
Indenture, dated as of December 5, 2019, between Diamondback Energy, Inc. and Computershare Trust Company, National Association, as successor trustee to Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 5, 2019).
4.4
First Supplemental Indenture, dated as of December 5, 2019, among Diamondback Energy, Inc., Diamondback E&P LLC, as successor by merger to Diamondback O&G LLC, and Computershare Trust Company, National Association, as successor trustee to Wells Fargo Bank, National Association (including the forms of 3.250% Senior Notes due 2026 and 3.500% Senior Notes due 2029) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 5, 2019).
4.5
Third Supplemental Indenture, dated as of March 24, 2021, among Diamondback Energy, Inc., Diamondback E&P LLC, as successor by merger to Diamondback O&G LLC, and Computershare Trust Company, National Association, as successor trustee to Wells Fargo Bank, National Association (including the forms of 3.125% Senior Notes due 2031 and 4.400% Senior Notes due 2051) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 24, 2021).
4.6
Fourth Supplemental Indenture, dated as of June 30, 2021, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as successor trustee to Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 5, 2021).
4.7
Fifth Supplemental Indenture, dated as of March 17, 2022, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as trustee (including the form of 4.250% Senior Notes due 2052) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 17, 2022).
4.8
Sixth Supplemental Indenture, dated as of October 28, 2022, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association (including the form of 6.250% Senior Notes due 2033) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 28, 2022).
4.9
Indenture, dated as of October 16, 2019, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor, and Wells Fargo Bank, National Association, as trustee (including the form of 5.375% Senior Notes due 2027) (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K of Viper Energy, Inc., as successor issuer to Viper Energy Partners LP (File 001-36505) filed on October 17, 2019).
4.10
First Supplemental Indenture, dated as of November 13, 2023, among Viper Energy, Inc., as successor issuer to Viper Energy Partners LP, and Computershare Trust Company, National Association, as trustee, relating to 5.375% Senior Notes due 2027 (incorporated by reference to Exhibit 10.2 of Viper Energy, Inc.’s Current Report on Form 8-K (File 001-36505) filed on November 17, 2023).
4.11
Indenture, dated as of October 19, 2023, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor and Computershare Trust Company National Association, as trustee (including the form of Viper Energy Partners LP’s 7.375% Senior Notes due 2031) (incorporated by reference to Exhibit 4.1 of the Current Report on Form 8-K of Viper Energy, Inc., as successor issuer to Viper Energy Partners LP, (File 001-36505), filed on October 25, 2023).
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3. Exhibits
Exhibit NumberDescription
4.12
First Supplemental Indenture, dated as of November 13, 2023, by and between Viper Energy, Inc., as the successor issuer to Viper Energy Partners LP, and Computershare Trust Company, National Association, as trustee, relating to 7.375% Senior Notes due 2031 (incorporated by reference to Exhibit 10.3 to Viper Energy, Inc.’s Current Report on Form 8-K (File 001-36505) filed on November 17, 2023).
4.13
Subordinated Promissory Note, dated as of October 16, 2019, made by Viper Energy Partners LLC in favor of Viper Energy Partners LP (incorporated by reference to Exhibit 10.2 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019).
4.14
Subordinated Promissory Note, dated as of October 19, 2023, made by Viper Energy Partners LLC in favor of Viper Energy Partners LP (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K of Viper Energy, Inc., as successor issuer to Viper Energy Partners LP (File 001-36505), filed on October 25, 2023).
4.15
Form of Indenture, dated September 1, 1996, between Energen Corporation and The Bank of New York as trustee (incorporated by reference to Exhibit 4(i) to Energen Corporation’s Registration Statement on Form S-3 (Registration No. 333-11239), filed with the SEC on August 30, 1996).
4.16
Amended and Restated Officers’ Certificate, dated as of February 27, 1998, between Energen Corporation and The Bank of New York as trustee, relating to the Medium-Term Notes, Series B, due 2028 (incorporated by reference to Exhibit 4(a)(iii) to the Form 10-K, File No. 001-7810, filed by Energen Corporation with the SEC on February 28, 2018).
4.17
Indenture, dated as of March 1, 2012, between QEP Resources, Inc. and Wells Fargo Bank, National Association as trustee (incorporated by reference to Exhibit 4.1 to QEP Resources Inc.’s Current Report on Form 8-K, filed with the SEC on March 1, 2012).
4.18
Officer’s Certificate, dated as of March 1, 2012 (including the form of the 5.375% Notes due 2022) (incorporated by reference to Exhibit 4.2 to QEP Resources, Inc.’s. Current Report on Form 8-K, filed with the SEC on March 1, 2012).
4.19
Officer’s Certificate, dated as of September 12, 2012 (incorporated by reference to Exhibit 4.1 to QEP Resources, Inc.’s Current Report on Form 8-K, filed with the SEC on September 14, 2012).
4.20
Officer’s Certificate, dated as of November 21, 2017 (including the form of the 5.625% Senior Notes due 2026) (incorporated by reference to Exhibit 4.2 to QEP Resources, Inc.’s Current Report on Form 8-K, filed with the SEC on November 21, 2017).
4.21
First Supplemental Indenture, dated as of March 23, 2021, among QEP Resources, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 24, 2021).
4.22
Indenture, dated as of December 13, 2022, between Diamondback Energy, Inc. and Computershare Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 13, 2022).
4.23
First Supplemental Indenture, dated as of December 13, 2022, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as trustee (including the form of 6.250% Senior Notes due 2053) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 13, 2022).
10.1+
2021 Amended and Restated Diamondback Energy, Inc. Equity Incentive Plan (incorporated by reference to Appendix B to Schedule DEF 14A filed by the Company with the SEC on April 23, 2021).
10. 2+*
Amendment No. 1 to 2021 Amended and Restated Diamondback Energy, Inc. Equity Incentive Plan, adopted effective as of February 11, 2024.
10.3+
2021 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 of the Annual Report on Form 10-K (File 001-35700) filed by the Company with the SEC on February 25, 2021).
10.4+
2021 Form of Performance Vesting Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.5 of the Annual Report on Form 10-K (File 001-35700) filed by the Company with the SEC on February 25, 2021).
10.5+
2022 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.6 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 23, 2023).
10.6+
2022 Form of Performance Vesting Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.7 of the Annual Report on Form 10-K (File 001-35700) filed by the Company with the SEC on February 23, 2023).
10.7+
2023 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.8 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 23, 2023).
10.8+
2023 Form of Performance Vesting Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.9 of the Annual Report on Form 10-K (File 001-35700) filed by the Company with the SEC on February 23, 2023).
10.9+*
2024 Form of Time Vesting Restricted Stock Unit Award Agreement.
10.10+*
2024 Form of Performance-Vesting Restricted Stock Unit Agreement.
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3. Exhibits
Exhibit NumberDescription
10.11+
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.12+
Diamondback Energy, Inc. Amended and Restated Senior Management Severance Plan, adopted effective as of February 21, 2022 (including a form of participation agreement attached thereto as Schedule C) (incorporated by reference to Exhibit 10.9 of the Annual Report on Form 10-K (File 001-35700) filed by the Company with the SEC on February 24, 2022).
10.13+*
Amendment No. 1 to Diamondback Energy, Inc. Amended and Restated Senior Management Severance Plan, adopted effective as of February 11, 2024.
10.14+
Form of Participation Agreement (incorporated by reference from Schedule C-2 to Diamondback Energy, Inc. Senior Management Severance Plan filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K (File 001-35700) on February 27, 2020).
10.15
Executive Annual Incentive Compensation Plan adopted in February 2021 (incorporated by reference to Exhibit 10.11 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2021).
10.16
Second Amended and Restated Credit Agreement, dated as of November 1, 2013, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
10.17
First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, by and among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014).
10.18
Second Amendment to the Second Amended and Restated Credit Agreement, dated as of November 13, 2014, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, the guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 18, 2014).
10.19
Third Amendment, dated as of June 21, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 27, 2016).
10.20
Fourth Amendment, dated as of December 15, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 20, 2016).
10.21
Fifth Amendment, dated as of November 28, 2017, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 4, 2017).
10.22
Eighth Amendment to the Second Amended and Restated Credit Agreement, dated as of October 26, 2018, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 1, 2018).
10.23
Ninth Amendment to Second Amended and Restated Credit Agreement and Fourth Amendment to Amended and Restated Guaranty and Collateral Agreement, dated as of November 29, 2018, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 6, 2018).
10.24
Tenth Amendment to Second Amended and Restated Credit Agreement, dated as of March 25, 2019, between Diamondback, as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K (File No. 00 1-35700), filed by the Company with the SEC on March 29, 2019).
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3. Exhibits
Exhibit NumberDescription
10.25
Eleventh Amendment to Second Amended and Restated Credit Agreement, dated as of June 28, 2019, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on July 3, 2019).
10.26
Twelfth Amendment to Second Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Guaranty Agreement, dated as of June 2, 2021, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 8, 2021).
10.27
Thirteenth Amendment to Second Amended and Restated Credit Agreement, dated as of June 2, 2022, between Diamondback Energy, Inc., as parent guarantor, Diamondback E&P LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on June 7, 2022).
10.28
Amended and Restated Credit Agreement, dated as of July 20, 2018, by and among, Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Current Report on Form 8-K (File 001-36505) filed by Viper Energy Partners LP on July 26, 2018).
10.29
Second Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 24, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Form 8-K (File 001-36505) filed on September 30, 2019).
10.30
Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Form 8-K (File 001-36505) filed on October 10, 2019).
10.31
Fourth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 29, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-36505) filed on December 5, 2019).
10.32
Fifth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of May 11, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2020).
10.33
Sixth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of November 6, 2020, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on November 12, 2020).
10.34
Eighth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of November 15, 2021, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File No. 001-36505) filed on November 18, 2021).
10.35
Ninth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of November 18, 2022, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.18 of the Viper Energy Partners LP’s Annual Report on Form 10-K (File 001-36505) filed on February 23, 2023).
10.36
Tenth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of May 31, 2023, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Viper Energy Partners LP’s Current Report on Form 8-K (File No. 001-36505) filed on June 6, 2023).
10.37
Eleventh Amendment to Amended and Restated Senior Secured Revolving Credit Agreement dated as of September 22, 2023, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed on September 28, 2023).
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3. Exhibits
Exhibit NumberDescription
10.38
Twelfth Amendment to Amended and Restated Senior Secured Revolving Credit Agreement dated as of September 22, 2023, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed on September 28, 2023).
10.39
Consent Letter, dated August 28, 2019, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File 001-35700) filed on September 4, 2019).
21.1*
Subsidiaries of the Registrant.
22.1
List of Issuers and Guarantors Subsidiaries (incorporated by reference to Exhibit 22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 5, 2021).
23.1*
Consent of Grant Thornton LLP.
23.2*
Consent of Ryder Scott Company, L.P. with respect to the audit of Diamondback Energy, Inc. estimated reserves.
23.3*
Consent of Ryder Scott Company, L.P. with respect to the audit of Viper Energy,Inc. estimated reserves.
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
97.1*
Diamondback Energy Inc. Clawback Policy.
99.1*
Audit Report of Ryder Scott Company, L.P., dated January 16, 2024, with respect to an audit of the proved reserves, future production and income attributable to certain leasehold interests of Diamondback Energy, Inc. as of December 31, 2023.
99.2*
Audit Report of Ryder Scott Company, L.P., dated January 16, 2024, with respect to an audit of the proved reserves, future production and income attributable to certain royalty interests of Viper Energy, Inc., a subsidiary of Diamondback Energy, Inc., as of December 31, 2023.
99.3#
Form of Stockholders Agreement, by and between, Diamondback Energy, Inc. and the stockholders party thereto (incorporated by reference to Exhibit 99.1 to the Form 8-K, File No. 001-35700, filed by Diamondback Energy, Inc. with the SEC on February 12, 2024).
101The following financial information from the Company’s Annual Report on Form 10-K for the year ended December 31, 2023, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
_______________
*Filed herewith.
**The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
+Management contract, compensatory plan or arrangement.
#The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.

ITEM 16. FORM 10-K SUMMARY
None.

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Table of Contents
SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMONDBACK ENERGY, INC.
Date:February 22, 2024
/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
(Principal Executive Officer)

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/s/ Travis D. SticeChairman of the Board, Chief Executive Officer and DirectorFebruary 22, 2024
Travis D. Stice(Principal Executive Officer)
/s/ Vincent K. BrooksDirectorFebruary 22, 2024
Vincent K. Brooks
/s/ David L. HoustonDirectorFebruary 22, 2024
David L. Houston
/s/ Rebecca A. KleinDirectorFebruary 22, 2024
Rebecca A. Klein
/s/ Stephanie K. MainsDirectorFebruary 22, 2024
Stephanie K. Mains
/s/ Mark L. PlaumannDirectorFebruary 22, 2024
Mark L. Plaumann
/s/ Melanie M. TrentDirectorFebruary 22, 2024
Melanie M. Trent
/s/ Frank D. TsuruDirectorFebruary 22, 2024
Frank D. Tsuru
/s/ Steven E. WestDirectorFebruary 22, 2024
Steven E. West
/s/ Kaes Van’t HofPresident and Chief Financial OfficerFebruary 22, 2024
Kaes Van’t Hof(Principal Financial Officer)
/s/ Teresa L. DickChief Accounting Officer, Executive Vice President and Assistant SecretaryFebruary 22, 2024
Teresa L. Dick(Principal Accounting Officer)

129