Diamondback Energy, Inc. (FANG)

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 in Item 8. Financial Statements and Supplementary Data of this 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 discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking 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. As of December 31, 2024, we have one reportable segment, the upstream segment. See Note 1—Description of the Business and Basis of Presentation and Note 18—Segment Information in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

2024 Financial and Operating Highlights

•We recorded net income of $3.3 billion.

•Increased our annual base dividend to $4.00 per share of common stock in the fourth quarter of 2024, paid dividends to stockholders of $1.6 billion during 2024 and declared a base cash dividend payable in the first quarter of 2025 of $1.00 per share of common stock.

•Increased our common stock repurchase program authorization to $6.0 billion, excluding excise taxes, and repurchased $959 million of our common stock, leaving approximately $2.7 billion available for future purchases under our common stock repurchase program at December 31, 2024.

•Our cash operating costs were $11.09 per BOE, including lease operating expenses of $5.87 per BOE, cash general and administrative expenses of $0.68 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.54 per BOE.

•Issued the April 2024 Notes for an aggregate of $5.5 billion in proceeds and incurred $1.0 billion in initial borrowings under the Tranche A Loans (as defined below in “—Transactions and Recent Developments”) to fund a portion of the cash consideration for the Endeavor Acquisition.

•Our average production was 598,284 MBOE/d.

•Drilled 372 gross horizontal wells (including 342 in the Midland Basin and 30 in the Delaware Basin).

•Turned 410 gross operated horizontal wells (including 391 in the Midland Basin and 19 in the Delaware Basin) to production.

•As of December 31, 2024, we had approximately 860,719 net acres, which primarily consisted of 737,181 net acres in the Midland Basin and 123,218 net acres in the Delaware Basin. As of December 31, 2024, we had an estimated 9,188 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 987,861 gross acres and 35,671 net royalty acres in the Permian Basin. We operate approximately 52% of these net royalty acres.

•Incurred capital expenditures, excluding acquisitions, of $2.9 billion.

Transactions and Recent Developments

2025 Transactions

Pending Double Eagle Acquisition

On February 14, 2025, we entered into a definitive securities purchase agreement with Double Eagle to effect the pending Double Eagle Acquisition for consideration of $3.0 billion in cash and approximately 6.9 million shares of our common stock, subject to customary adjustments. The pending Double Eagle Acquisition consists of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets. We intend to fund the cash portion of the pending Double Eagle Acquisition through a combination of cash on hand, borrowings under our credit facility or proceeds from term loans and senior notes offerings. The pending Double Eagle Acquisition is expected to close in the second quarter of 2025, subject to the satisfaction of customary closing conditions and regulatory approval.

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Viper 2025 Equity Offering

On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of its Class A common stock (the “Viper 2025 Equity Offering”), which included 3.70 million shares issued pursuant to an option to purchase additional shares of its Class A common stock granted to the underwriters at a price to the public of $44.50 per share. Viper received total net proceeds for the Viper 2025 Equity Offering of approximately $1.2 billion after the underwriters’ discount and estimated transaction costs.

Pending 2025 Drop Down Transaction

On January 30, 2025, EER LP and the Endeavor Subsidiaries, each of which is our subsidiary, entered into a definitive equity purchase agreement with Viper and Viper LLC to divest the Endeavor Subsidiaries to Viper in exchange for consideration consisting of (i) $1.0 billion in cash and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock (which securities are exchangeable for an equal number of Viper’s Class A common stock), in each case subject to customary closing adjustments, including for net title benefits. The pending 2025 Drop Down is expected to close in the second quarter of 2025, subject to the approval by Viper’s stockholders, regulatory clearance and the satisfaction or waiver of other closing conditions. Viper intends to fund the cash consideration for the pending 2025 Drop Down with the net proceeds from the Viper 2025 Equity Offering discussed above. The mineral and royalty interests owned by the Endeavor Subsidiaries being divested in the pending 2025 Drop Down represent approximately 22,847 net royalty acres located primarily in the Permian Basin. The Endeavor Subsidiaries being sold in the pending 2025 Drop Down were acquired by us in the recently completed Endeavor Acquisition.

See Note 17—Subsequent Events in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the pending Double Eagle Acquisition, the Viper 2025 Equity Offering and the pending 2025 Drop Down.

2024 Diamondback Acquisitions and Divestitures

Endeavor Acquisition

On September 10, 2024, we completed the Endeavor Acquisition for consideration consisting of $7.3 billion in cash, subject to certain customary post-closing adjustments, and approximately 117.27 million shares of our common stock. The Endeavor Acquisition included approximately 500,849 gross (361,927 net) acres, which are primarily located in the Permian Basin. The cash consideration for the Endeavor Acquisition was funded through a combination of cash on hand, the net proceeds of the Company’s $5.5 billion April 2024 Senior Notes offering and $1.0 billion in borrowings under the Tranche A Loans (as defined and discussed below). See Note 5—Endeavor Energy Resources, LP Acquisition in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition.

TRP Energy, LLC Asset Exchange

On December 20, 2024, we completed an exchange agreement with TRP Energy, LLC (“TRP”), in which we exchanged approximately 47,034 gross (35,673 net) acres located in the Delaware Basin and $325 million in cash, subject to customary post-closing adjustments, for certain of TRP’s assets consisting of approximately 21,582 gross (15,421 net) acres located in the Midland Basin (the “TRP Exchange”). The TRP Exchange was valued at approximately $1.4 billion.

WTG Midstream Transaction

On July 15, 2024, Remuda Midstream Holdings LLC, (the “WTG joint venture”) sold its WTG Midstream LLC subsidiary (the “WTG Midstream Transaction”), resulting in proceeds to us of 10.1 million common units of Energy Transfer LP and $190 million in cash, subject to customary closing adjustments. At the closing of the WTG Midstream Transaction, the value attributable to us for the 10.1 million common units was approximately $135 million, of which we received approximately $81 million with the remaining $54 million held in escrow pursuant to an escrow agreement entered into by the WTG joint venture. A gain of approximately $74 million was recognized for the WTG Transaction in the third quarter of 2024.

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2024 Viper Acquisitions

Viper Tumbleweed Acquisitions

On October 1, 2024, Viper and Viper LLC completed the Viper TWR Acquisition, for which the consideration consisted of approximately (i) $464 million in cash, (ii) 10.09 million Viper LLC units, including transaction costs and certain customary post-closing adjustments, (iii) the TWR Class B Option, and (iv) contingent cash consideration of up to $41 million payable in January of 2026. The mineral and royalty interests acquired in the Viper TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin.

On September 3, 2024 Viper and Viper LLC acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (i) the Viper Q Acquisition for a purchase price of approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and a contingent cash consideration of up to $5 million payable in January of 2026, and (ii) MC TWR Royalties, LP and MC TWR Intermediate, LLC the Viper M Acquisition for a purchase price of approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and a contingent cash consideration of up to $4 million payable in January of 2026. The mineral and royalty interests acquired in the Viper Q & M Acquisitions, represent approximately 406 and 267 net royalty acres located primarily in the Permian Basin, respectively.

See Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the TRP Exchange, the Viper Tumbleweed Acquisitions and the WTG Midstream Transaction.

2024 Capital Transactions

Viper 2024 Equity Offering

On September 13, 2024, Viper completed an underwritten public offering of approximately 11.5 million shares of its Class A common stock at a price to the public of $42.50 per share for total net proceeds to Viper of approximately $476 million (the “Viper 2024 Equity Offering”).

See Note 10—Stockholders' Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Viper 2024 Equity Offering.

April 2024 Notes Offering

On April 18, 2024, we issued an aggregate of $5.5 billion in senior notes, consisting of (i) $850 million aggregate principal amount of 5.200% Senior Notes due April 18, 2027 (the “2027 Notes”), (ii) $850 million aggregate principal amount of 5.150% Senior Notes due January 30, 2030 (the “2030 Notes”), (iii) $1.3 billion aggregate principal amount of 5.400% Senior Notes due April 18, 2034 (the “2034 Notes”), (iv) $1.5 billion aggregate principal amount of 5.750% Senior Notes due April 18, 2054 (the “2054 Notes”), and (v) $1.0 billion aggregate principal amount of 5.900% Senior Notes due April 18, 2064 (the “2064 Notes” and together with the 2027 Notes, the 2030 Notes the 2034 Notes and the 2054 Notes, the “April 2024 Notes”).

Term Loan Agreement

In connection with the Endeavor Acquisition, we entered into a Term Loan Credit Agreement with Citibank, N.A. on February 29, 2024 (the “Term Loan Agreement”). The Term Loan Agreement provided the Company with the ability to borrow up to $1.5 billion, which was comprised of $1.0 billion of Tranche A Loans (the “Tranche A Loans”) and $500 million of Tranche B Loans (the “Tranche B Loans”). On August 2, 2024, we terminated our undrawn Tranche B Loans. Initial borrowings of $1.0 billion under the Tranche A Loans were used to fund a portion of the cash consideration for the Endeavor Acquisition.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, extreme weather conditions and other substantially variable factors, influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2024, 2023 and 2022 the NYMEX WTI prices averaged $75.76, $77.60 and $94.33 per Bbl, respectively, and the NYMEX Henry Hub prices averaged $2.41, $2.66 and $6.54 per MMBtu, respectively.

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For additional information around risks related to commodity prices, see Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Outlook

During 2024, we had total capital expenditures of $2.9 billion, which was consistent with our guidance presented in November 2024. In 2025, we expect production and capital expenditures to increase as a result of the Endeavor Acquisition the Viper Tumbleweed Acquisitions, and the pending Double Eagle Acquisition, if consummated. Giving effect to the pending Double Eagle Acquisition, we have currently budgeted 2025 total capital spend of $3.80 billion to $4.20 billion, which at the midpoint is an increase of 36% year over year. Given the volatile current macro environment for oil prices and near-term global oil supply and demand dynamics, we have made the capital allocation decision to focus on free cash flow (as defined in “— Capital Requirements”) generation and capital efficiency over volume growth in 2025.

As part of the agreement with Double Eagle, we have also agreed to accelerate development on a portion of our non-core southern Midland Basin acreage. This acceleration is expected to bring forward net asset value to us by developing our lower quality acreage at a faster pace than current expectations. As a result, we expect significant free cash flow growth in 2026 and beyond with minimal capital deployment through this accelerated development plan.

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% (down from 75%) of our quarterly free cash flow. Because we added debt to fund the cash portion of the Endeavor Acquisition and expect to add additional debt upon completion of the pending Double Eagle Acquisition, we are allocating more free cash flow to pay down our debt, with a near-term goal to reduce net debt to $10 billion. Our long-term target is to maintain our net debt between $6 billion and $8 billion through free cash flow generation and potential non-core asset sales as demonstrated by our recently announced commitment to sell at least $1.5 billion of non-core assets to help accelerate debt reduction and maintain a strong balance sheet. We also remain focused on our long-term priority to return cash to our stockholders.

In the Midland Basin, we continued to have positive results across our core development areas located within Midland, Martin, Ector, Glasscock, Reagan, Andrews and Howard counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.

In the Delaware Basin, we continued to target the Wolfcamp and Bone Spring formations across our primary development areas located in Pecos, Reeves and Ward counties. Collectively, the Delaware Basin accounted for approximately 5% of our total development in 2024, and we expect a similar portion of our total development to be focused in these areas in 2025.

As of December 31, 2024, we were operating 19 drilling rigs and four completion crews and currently intend to operate between 13 and 19 drilling rigs and between four and six completion crews in 2025 on average across our current acreage position in the Midland and Delaware Basins.

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2025 Guidance

The following table presents our current estimates, which give effect to the estimated contribution related to the pending Double Eagle Acquisition, of certain financial and operating results for the full year of 2025, as well as production and cash tax guidance for the first quarter of 2025:

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Results of Operations

Comparison of the Years Ended December 31, 2024 and 2023

For a discussion of the results of operations for the year ended December 31, 2023 as compared to the year ended December 31, 2022, 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, 2023 (filed with the SEC on February 22, 2024), 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:

(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.

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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, 2024 and 2023:

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.

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues increased by approximately $1.9 billion, or 23%, to $10.1 billion in 2024 compared to $8.2 billion in 2023. This net increase consisted of an additional $2.5 billion attributable to the 34% growth in our combined production volumes, and a reduction of $596 million attributable to lower average prices received for our oil, natural gas and natural gas liquids production.

Approximately 72% of the increase in combined production volumes is attributable to the Endeavor Acquisition, 4% is attributable to Viper’s GRP Acquisition and 1% is attributable to Viper’s Tumbleweed Acquisitions. The remainder of the change is attributable to new wells drilled on previously existing acreage.

See Note 4—Acquisitions and Divestitures and Note 5—Endeavor Energy Resources, LP Acquisition in Item 8. Financial Statements and Supplementary Data of this report for further definition and discussion of Viper’s GRP Acquisition, the Viper Tumbleweed Acquisitions and the Endeavor Acquisition.

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 sales of purchased oil from third parties for the year ended December 31, 2024 and 2023:

Other Revenues. The following table shows the other revenues for the year ended December 31, 2024 and 2023:

Other operating income decreased by $30 million in 2024 compared to 2023 primarily due to (i) a $37 million reduction in midstream service revenues following the sale of the Deep Blue Water Assets in the third quarter of 2023, (ii) a $5 million increase in midstream service revenues resulting from the Endeavor Acquisition and (iii) other individually insignificant changes.

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Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2024 and 2023:

Lease operating expenses increased by $414 million, or $0.53 per BOE in 2024 as compared to 2023. The increase primarily consists of (i) $220 million in lease operating expenses related to the Endeavor Acquisition, (ii) $66 million in additional costs incurred for water services as a result of divesting the Deep Blue Water Assets in the third quarter of 2023, (iii) $65 million due to an increase in legacy production volumes, (iv) $48 million due to an increase in workover expense, (v) $12 million due to an increase in electrical generation costs, and (vi) other individually insignificant changes.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2024 and 2023:

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of oil, natural gas and natural gas liquids revenues remained consistent during 2024 compared to 2023.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes increased by $31 million in 2024 compared to 2023 primarily due to $28 million of ad valorem taxes accrued on properties acquired as part of the Endeavor Acquisition and other individually insignificant changes.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the years ended December 31, 2024 and 2023:

Gathering, processing and transportation expense increased by $69 million in 2024 compared to 2023 primarily due to an increase in our production from legacy wells as well as an increase in our contractual rates throughout the year. The decrease in the overall rate per BOE between 2024 and 2023 is due to recording gathering, processing and transportation charges for production from the Endeavor Acquisition as a reduction to revenue in accordance with the terms of the acquired contracts.

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Depreciation, Depletion, Amortization and Accretion. The following table shows the components of our depreciation, depletion and amortization expense for the years ended December 31, 2024 and 2023:

The increase in depletion of proved oil and natural gas properties of $1.1 billion in 2024 as compared to 2023 consists of an additional (i) $567 million from the growth in production volumes, and (ii) $523 million due to applying a higher depletion rate in 2024. The increase in depletion rate was primarily due to the addition of higher value leasehold costs and proved reserves from the Endeavor Acquisition and Viper’s Tumbleweed Acquisitions into the depletable base in 2024.

General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2024 and 2023:

The increase in general and administrative expenses of $52 million in 2024 compared to 2023 was primarily due to (i) a $41 million increase in employee compensation and benefit costs related to additional headcount largely from the Endeavor Acquisition and annual compensation adjustments, (ii) a $12 million increase in software costs, and (iii) offsetting changes in other individually insignificant items.

Other Operating Costs and Expenses. The following table shows the other operating costs and expenses for the year ended December 31, 2024 and 2023:

Merger and integration expenses in 2024 include costs incurred in connection with the Endeavor Acquisition primarily for severance and accelerated incentive compensation payments to former Endeavor employees as well as investment banking and legal costs. See Note 5—Endeavor Energy Resources, LP Acquisition in Item 8. Financial Statements and Supplementary Data of this report for further details regarding expenses incurred the Endeavor Acquisition.

Other operating expenses decreased by $37 million in 2024 compared to 2023 primarily due to a $77 million reduction in midstream services costs as a result of the sale of the Deep Blue Water Assets in the third quarter of 2023. This reduction was partially offset by increases of (i) $25 million in midstream services costs following the Endeavor Acquisition, (ii) $8 million in net losses on the sale of property, plant and equipment in 2024, (iii) $7 million primarily attributable to the write off of certain saltwater disposal assets during 2024, and (iv) other individually insignificant changes.

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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, 2024 and 2023:

(1)The year ended December 31, 2024 includes cash paid on interest rate swaps terminated prior to their contractual maturity of $37 million and cash paid for the early settlement of treasury lock contracts of $25 million

The change from a loss to a gain on derivative instruments in 2024 compared to 2023 primarily reflects (i) a $374 million increase in the value of our unsettled natural gas contracts due to a decrease in market prices for natural gas compared to our contract prices, (ii) a $129 million increase in cash received on the settlement of natural gas contracts, and (iii) a $10 million increase in the value of our interest rate swap contracts primarily due to a decline in expected future interest rates. These increases were partially offset by (i) a $60 million increase in cash paid on the settlement of interest rate derivatives (ii) a $43 million decrease in the value of our unsettled oil contracts due to an increase in market prices for oil compared to our contract prices, (iii) an $11 million increase in cash paid for the settlement of oil contracts, and (iv) other individually insignificant changes.

See Note 13—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, 2024 and 2023:

Interest expense, net decreased $24 million in 2024 compared to 2023 primarily due to (i) an additional $165 million in capitalized interest costs, which reduce interest expense, (ii) an increase in interest income of $138 million due to holding proceeds from the April 2024 Notes in short-term interest bearing accounts until the close of the Endeavor Acquisition, and (iii) a $12 million decrease in interest expense on our revolving credit facility due to lower average borrowings outstanding in 2024. These reductions were largely offset by (i) an increase of $233 million in interest expense on senior notes related primarily to the issuance of the April 2024 Notes and Viper’s 7.375% Senior Notes due 2031 which were issued in the fourth quarter of 2023, (ii) an increase of $39 million in amortization of debt issuance costs primarily related to our terminated Bridge Facility, Tranche A Loans and April 2024 Notes, and (iii) a $19 million increase in interest expense incurred in connection with the Tranche A Loans.

See Note 9—Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding outstanding borrowing, interest expense and gain (loss) on extinguishment of debt.

Other income (expense), net for 2024 includes a gain recorded on the WTG Midstream Transaction of approximately $74 million compared to 2023 including a $53 million gain on the sale of our equity method investment in Gray Oak Pipeline, LLC (“Gray Oak”), partially offset by various other insignificant activity.

The decrease in income from our equity investments primarily reflects reductions of (i) $17 million due to the sale of our interest in OMOG JV LLC in the third quarter of 2023, (ii) $11 million due to the WTG Midstream Transaction, and (ii) other individually insignificant activity.

See Note 8—Equity Method Investments and Related Party Transactions in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

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Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2024 and 2023:

The change in our income tax provision for 2024 compared to 2023 was primarily due to a lower effective annual tax rate following the release of Viper’s $156 million valuation allowance in the fourth quarter of 2024. See Note 12—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity have included cash flows from operations, proceeds from our public equity offerings, issuances of common stock in connection with acquisitions, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have 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, 2024, we had approximately $2.6 billion of liquidity consisting of $134 million in standalone cash and cash equivalents and $2.5 billion available under our credit facility. As discussed below, our capital budget for 2025, which gives effect to the pending Double Eagle Acquisition, is $3.80 billion to $4.20 billion. As of December 31, 2024, we have approximately $900 million of Tranche A Loans maturing in September 2025.

Future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the 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 13—Derivatives in Item 8. Financial Statements and Supplementary Data and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk of 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.

Cash Flow

Our cash flows for the years ended December 31, 2024 and 2023 are presented below:

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.

The increase in operating cash flows for the year ended December 31, 2024 compared to the same period in 2023 primarily resulted from (i) an increase of $1.8 billion in total revenue, excluding sales of purchased oil, (ii) an additional $138 million in interest income, and (iii) a reduction of $59 million in cash paid on settlements of derivatives. These cash inflows were partially offset by an increase in our cash operating expenses, excluding purchased oil expense, of

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approximately $903 million related primarily to merger and integration costs incurred in connection with the Endeavor Acquisition and additional lease operating expenses, (ii) an increase of $253 million in cash paid for taxes, (iii) an increase of $123 million in cash paid for interest, net of capitalized amounts, and (iv) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were 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, 2024 and 2023 was for drilling and completion costs in conjunction with our development program as well as the purchase of oil and gas properties including the Endeavor Acquisition and Viper’s Tumbleweed Acquisitions in 2024 and the Lario Acquisition and Viper’s GRP Acquisition in 2023. 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:

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 2024 of this report.

Financing Activities

During the year ended December 31, 2024, net cash used in financing activities was primarily attributable to $5.5 billion of proceeds from the issuance of the April 2024 Notes, $900 million in borrowings on our Tranche A Loans, net of repayments, $476 million in proceeds from the Viper 2024 Equity Offering, $451 million in proceeds from the sale of our shares of Viper’s Class A common stock and $2 million in borrowings on our credit facilities, net of repayments. These cash inflows were partially offset by (i) $1.6 billion of dividends paid to stockholders, (ii) $959 million of repurchases as part of the share repurchase program, (iii) $227 million in dividends to non-controlling interest, (iv) $99 million of debt issuance costs primarily associated with the April 2024 Notes, Term Loan Agreement and Bridge Facility, and (vi) $39 million in cash paid for tax withholdings on vested employee stock awards.

Net cash used in financing activities for the year ended December 31, 2023 was primarily attributable to (i) $1.4 billion of dividends paid to stockholders, (ii) $935 million of repurchases as part of the Diamondback and Viper share repurchase programs, (iii) $134 million paid for the retirement of outstanding principal on certain senior notes, and (iv) $129 million in distributions to non-controlling interest. The cash outflows were partially offset by (i) $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.

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 Double Eagle 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.

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As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and/or 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. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and Other Debt Instruments

As of December 31, 2024, our debt, including the debt of Viper, consisted of approximately $12.0 billion in aggregate outstanding principal amount of senior notes, $900 million in aggregate outstanding short-term borrowings under the Tranche A Loans and $261 million in aggregate outstanding borrowings under revolving credit facilities.

As of December 31, 2024, the maximum credit amount available under our credit agreement was $2.5 billion, which may be increased to a total maximum commitment amount of $2.6 billion, with no outstanding borrowings and $2.5 billion available for future borrowings. Our credit agreement matures on June 2, 2029.

Viper LLC’s Credit Agreement

The Viper LLC 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, with a borrowing base and elected commitment amount of $1.3 billion. At December 31, 2024, there were $261 million of outstanding borrowings and $1.0 billion available for future borrowings under the Viper LLC credit agreement.

For additional discussion of our outstanding debt as of December 31, 2024, see Note 9—Debt in Item 8. Financial Statements and Supplementary Data of this report.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S which impact the interest rates we receive on our variable rate debt and interest rate swaps. 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. In September, we received an upgrade from two of the three major ratings agencies in the U.S., Standard and Poor’s Global Ratings Services and Fitch Investor Services. Currently, our credit ratings from the three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB);

•Fitch Investor Services (BBB+); and

•Moody’s Investor Services (Baa2).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in “—Outlook”, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit agreements, Tranche A Loans and senior notes, (iii) payments of other contractual obligations, (iv) cash commitments for dividends and repurchases of securities, and the pending Double Eagle Acquisition.

2025 Capital Spending Plan

We currently estimate that our 2025 capital budget, which gives effect to the pending Double Eagle Acquisition, will be $3.80 billion to $4.20 billion, including $3.13 billion to $3.44 billion for horizontal drilling and completions, $280 million to $320 million for non-operated activity and capital workovers and $390 million to $440 million spent on infrastructure, midstream and environmental capital expenditures. We currently expect to drill approximately 446 to 471 gross (406 to 428 net) horizontal wells and complete approximately 557 to 592 gross (526 to 560 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 11,500 feet.

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The amount and timing of our 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. 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.

Payments of Principal and Interest on Senior Notes and Tranche A Loans

At December 31, 2024, we have total principal payments due on our outstanding senior notes, including those of Viper, of $764 million in 2026, $1.3 billion in 2027, $73 million in 2028, $915 million in 2029 and $9.0 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $612 million in 2025, $1.2 billion cumulatively in the years from 2026 through 2027, $1.0 billion cumulatively in the years from 2028 and 2029, and $7.1 billion cumulatively between 2030 and 2064.

In addition to the senior notes, we have $900 million in aggregate outstanding borrowings under the Tranche A Loans due in 2025. See Note 9—Debt in Item 8. Financial Statements and Supplementary Data of this report for further discussion on the Tranche A Loans.

Other Contractual Obligations and Commitments

At December 31, 2024, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $2.8 billion, (ii) electrical power purchase commitments totaling $365 million (iii) asset retirement obligations totaling $592 million, (iv) electric fracturing fleet and related power generation services commitments totaling $199 million and (v) minimum purchase commitments for quantities of sand used in our drilling operations totaling $66 million. We expect to make aggregate payments of approximately $442 million for these commitments during 2025. See Note 7—Asset Retirement Obligations and Note 16—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 Energy LLC currently anticipate collectively contributing $500 million in follow-on capital to fund future growth in our Deep Blue Midland Basin LLC joint venture projects and acquisitions.

Return of Capital Commitment

Beginning in the first quarter of 2024, our board of directors approved a return of capital commitment of at least 50% (down from 75%) of our quarterly free cash flow to our stockholders 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 21, 2025, our board of directors declared a base cash dividend for the fourth quarter of 2024 of $1.00 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 properties across periods on a consistent basis.

Future base and variable 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 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.

On September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax. Since the inception of the stock repurchase program, we have repurchased an aggregate 25.84 million shares of our common stock for a total cost of $3.5 billion, excluding excise tax, as of February 21, 2025. Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue opportunistically purchasing shares under this repurchase program primarily with funds from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure

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programs. See Note 10—Stockholders' Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the repurchase program.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under the 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, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur 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 determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, 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 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 or financial position had the guarantor subsidiary operated as an independent entity.

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Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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 and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our board of directors.

Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural 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 estimation of proved reserves to be a critical accounting estimate.

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. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers as of December 31, 2024, 2023 and 2022. 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, 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 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 depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately $2.0 billion, or 16% of the change in the standardized measure of our total reserves from December 31, 2023 to December 31, 2024. No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2024, 2023 and 2022. Based on the historical 12-month average trailing SEC prices for oil and natural gas throughout 2024 and into 2025, we are not currently projecting a full cost ceiling impairment in the first quarter of 2025.

Additionally, 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 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, 2024, our unevaluated properties totaled $22.7 billion, which consisted of 433,335 net undeveloped leasehold acres with approximately 4,290 net acres set to expire in 2025. We did not record any impairment on our unevaluated properties during the year ended December 31, 2024, but any such future impairment could potentially be material to our consolidated financial statements.

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Business Combinations

We account for business combinations in which it has been determined we are the acquirer 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 estimates 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 market valuation approaches depending on the quality of information available to support management’s assumptions.

The most significant assumptions relate to the estimated fair values assigned to 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 oil 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 a proxy for fair market value; for example, the amount a willing buyer and seller 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 initially expected. See Note 4—Acquisitions and Divestitures and Note 5—Endeavor Energy Resources, LP Acquisition 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 business combinations including any significant changes in these estimates from the date of acquisition.

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 the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net 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 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 2024, 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 the full release of Viper’s remaining valuation allowance of $156 million. The positive evidence assessed included recent cumulative income due in part to commodity prices remaining consistently high, acquisitions of additional oil and gas properties, and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. As of December 31, 2024, Viper had a deferred tax asset of $185 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. As of December 31, 2024, 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.

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The accruals for deferred tax assets and liabilities are often based on unclear 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, 2024, 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

See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for recent accounting pronouncements not yet adopted, if any.

Off-Balance Sheet Arrangements

See Note 16—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for a discussion of our significant commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.

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 in Item 8. Financial Statements and Supplementary Data of this 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 discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking 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. As of December 31, 2023, we have one reportable segment, the upstream segment. See Note 1—Description of the Business and Basis 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 Delaware Basin).

•Turned 310 gross operated horizontal wells (including 263 in the Midland Basin and 47 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 operate approximately 49% of these net royalty acres.

•Incurred capital expenditures, excluding acquisitions, of $2.7 billion.

2023 Transactions and Recent Developments

Acquisitions

On November 1, 2023, Viper closed on the GRP Acquisition, which included 4,600 net royalty acres in the Permian Basin, plus an additional 2,700 net royalty acres in other major basins in exchange for approximately 9.02 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 (16,000 net) acres in the Midland Basin and certain related oil and gas assets in exchange for 4.33 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 equity method investments of approximately $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 of our common stock. The Endeavor Acquisition is expected to close in the fourth quarter of 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 39.5% 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 the future, extreme weather conditions and other substantially 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 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

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return cash to stockholders, and we believe using free cash flow to pay down newly-added debt is in the best long-term interest of our stockholders.

In the Midland Basin, we continued 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.

In the Delaware Basin, we continued to target the Wolfcamp and Bone Spring formations across our primary development areas located in Pecos, Reeves and Ward counties. Collectively, the Delaware Basin accounted for approximately 15% of our total development in 2023, and we expect a similar 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 in the Midland and Delaware Basins.

We have currently budgeted 2024 total capital spend of $2.30 billion to $2.55 billion, which at the midpoint is a reduction of 10% year over year due to a combination of lower well costs and lower activity expected in 2024. We expect to drill approximately 275 wells and turn approximately 310 wells to production, 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 natural 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 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.

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2024 Guidance

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

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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:

(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:

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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.

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues decreased by approximately $1.3 billion, or 14%, to $8.2 billion for the year ended December 31, 2023 from $9.6 billion for the year ended December 31, 2022, primarily due to a reduction of $3.0 billion attributable to lower average prices received for our oil production and to a lesser extent, our natural gas and natural gas liquids 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 sales of purchased oil from third parties for the year ended December 31, 2023 and 2022:

Other Revenues. The following table shows the other insignificant revenues for the year ended December 31, 2023 and 2022:

Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2023 and 2022:

Lease operating expenses increased by $220 million, or $0.71 per BOE for the year ended December 31, 2023 as compared to the same period in 2022. The increase primarily consists of (i) $119 million in lease operating expenses incurred on production volumes from the FireBird Acquisition and the Lario Acquisition, (ii) $33 million in additional costs incurred for water services as a result of divesting the Deep Blue Water Assets in 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 Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2023 and 2022:

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues decreased slightly for the year ended December 31, 2023 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, 2023 compared to the 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 the Lario Acquisition, partially offset by a decrease in tax rates for multiple taxing authorities.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the years ended December 31, 2023 and 2022:

The increase in gathering, processing and transportation expenses for the year ended December 31, 2023 compared to the 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 years ended December 31, 2023 and 2022:

The increase in depletion of proved oil and natural gas properties of $419 million for the year ended December 31, 2023 as compared to the same 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, 2023 and 2022:

The increase in general and administrative expenses for the year ended December 31, 2023 compared to the 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, 2023 and 2022:

The increase in 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:

(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 market 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:

The increase in net interest expense for the year ended December 31, 2023 compared to the 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, 2023 includes a $53 million gain on the sale of our equity method investment in Gray Oak and a $35 million gain on the sale of our equity method investment in OMOG as discussed further in Note 4—Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report, partially offset by various other insignificant expenses.

Gain (loss) on extinguishment of debt reflects the difference between the carrying value and reacquisition price for the repurchases and redemptions of various senior notes during the 2023 and 2022 periods.

See Note 8—Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding outstanding borrowings, interest expense and gain (loss) on extinguishment of debt.

The decrease in income from our equity investments primarily reflects a reduction of $19 million due to the sale of Gray Oak in January 2023 and an $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 $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 this report for further discussion.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2023 and 2022:

The change in our income tax provision for the year ended December 31, 2023 compared to the same period in 2022 was primarily due to the decrease in pre-tax income resulting largely from the decline in revenues from oil, natural gas and natural gas liquids and was partially offset by the discrete income tax benefit recognized for the year ended December 31, 2022 related to a reduction in Viper’s valuation allowance against its deferred tax assets. See Note 11—Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity have included cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have 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 Risk of 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:

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:

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 our business and 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. Continued prolonged volatility in the capital, financial and/or credit markets due to the war in Ukraine and Israel-Hamas war, and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and Senior Notes

As of December 31, 2023, the maximum credit amount available under our credit agreement was $1.6 billion, which may be increased to a total maximum commitment amount of $2.6 billion, with no outstanding borrowings. Our credit agreement matures on June 2, 2028, and may further extend it by one one-year extension pursuant to the terms set forth in the credit agreement.

Viper’s Credit Agreement

The Viper 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, with a borrowing base of $1.3 billion as of December 31, 2023, although Viper had an elected commitment amount of $850 million, based on Viper LLC’s oil and natural gas reserves and other factors. At December 31, 2023, there were $263 million of outstanding borrowings and $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 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.

For additional discussion of our outstanding debt 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 major ratings agencies in the U.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 three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB-);

•Fitch Investor Services (BBB); and

•Moody’s Investor Services (Baa2).

Any rating downgrades may result in additional letters of credit or 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 “—Outlook”, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit agreements and senior notes, (iii) payments of other contractual obligations, (iv) cash commitments for dividends and repurchases of securities, and (v) the pending Endeavor Acquisition.

2024 Capital Spending Plan

Our board of directors approved a 2024 capital budget for drilling, midstream infrastructure and environmental of $2.30 billion to $2.55 billion. We estimate that, of these expenditures, approximately:

•$2.10 billion to $2.33 billion will be spent primarily on drilling 265 to 285 gross (244 to 263 net) horizontal wells and completing 300 to 320 gross (273 to 291 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 11,500+ feet;

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

The amount and timing of our 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. 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.

Payments 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 properties across periods on a consistent basis.

Future base and variable 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 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 have 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 liquidity 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 the 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, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur 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 determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

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The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, 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 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 or financial position had the guarantor subsidiary operated as an independent entity.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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 and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our board of directors.

Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural 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 estimation of proved reserves to be a critical accounting estimate.

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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. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers as of December 31, 2023 and 2022 and 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, 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 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 depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately $1.3 billion, or 15% of the change in the standardized measure of our total reserves from December 31, 2022 to December 31, 2023. No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2023, 2022 and 2021. Based on the historical 12-month average trailing SEC prices for oil and natural gas throughout 2023 and into 2024, we are not currently projecting a full cost ceiling impairment in the first quarter of 2024.

Additionally, 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 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 properties 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 year ended December 31, 2023, but any such future impairment could potentially be material to our consolidated financial statements.

Commodity Derivatives

From time to time, we use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise 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 hedges 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 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 estimates 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 market valuation approaches depending on the quality of information 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 oil 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 a proxy for fair market value; for example, the amount a willing buyer and seller 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 initially 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 estimates from the date of acquisition.

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 the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net 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 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

See Note 2—Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data of this report for recent accounting pronouncements not yet adopted, if any.

Off-Balance Sheet Arrangements

See Note 15—Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for a discussion of our significant commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.

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 this Annual 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 Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. As of December 31, 2022, we have one reportable segment, the upstream segment. See Note 1—Description of the Business and Basis of Presentation and Note 17—Segment Information of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion.

2022 Financial and Operating Highlights

•We recorded net income of $4.4 billion for the year ended December 31, 2022.

•Increased our annual base dividend by 50% to $3.00 per share and paid dividends to stockholders of $1.6 billion during 2022 and in February 2023 declared a combined base and variable cash dividend of $2.95 per share of common stock, payable in the first quarter of 2023. Additionally on February 16, 2023, our board of directors approved an increase to the Company’s annual base dividend to $3.20 per share.

•Repurchased $1.1 billion of our common stock, leaving approximately $2.5 billion available for future purchases under our common stock repurchase program at December 31, 2022.

•During the year ended December 31, 2022, we issued $2.5 billion in principal amount of senior notes and retired an aggregate of $2.4 billion in principal amount of our then-outstanding senior notes.

•Our average production was 386,005 MBOE/d during the year ended December 31, 2022.

•During the year ended December 31, 2022, we drilled 240 gross horizontal wells (including 197 in the Midland Basin and 43 in the Delaware Basin).

•We turned 255 gross operated horizontal wells (including 213 in the Midland Basin and 42 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $1.9 billion during the year ended December 31, 2022.

•As of December 31, 2022, we had approximately 508,767 net acres, which primarily consisted of 325,540 net acres in the Midland Basin and 150,719 net acres in the Delaware Basin. As of December 31, 2022, we had an estimated 8,276 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 775,180 gross acres and 26,315 net royalty acres in the Permian Basin. We operate approximately 57% of these net royalty acres.

2022 Transactions and Recent Developments

Pending Divestiture Transactions

In February 2023, we entered into definitive agreements with unrelated third-party buyers to divest non-core assets consisting of approximately 19,000 net acres in Glasscock County and approximately 4,900 net acres in Ward and Winkler counties for combined total consideration of $439 million, subject to certain closing adjustments. The assets being sold in these pending transactions include approximately 2 MBO/d (7 MBOE/d) of 2023 production. Both of these transactions are expected to close in the second quarter of 2023, subject to completion of diligence and satisfaction of customary closing conditions.

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Lario Acquisition

On January 31, 2023, we closed on the Lario Acquisition, which included approximately 25,000 gross (15,000 net) acres in the Midland Basin and certain related oil and gas assets in exchange for 4.33 million shares of our common stock and $814 million, including certain customary closing adjustments.

Gray Oak Divestiture

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.

2022 Acquisition Activity

On January 18, 2022, we acquired, from an unrelated third-party seller, approximately 6,200 net acres in the Delaware Basin for $232 million in cash, including customary closing adjustments.

On August 24, 2022, we completed the merger with Rattler pursuant to which we acquired all of the approximately 38.51 million publicly held outstanding common units of Rattler in exchange for approximately 4.35 million shares of our common stock.

On November 30, 2022, we acquired 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 our common stock and $787 million of cash, including certain customary closing adjustments.

Additionally during the year ended December 31, 2022, we acquired, from unrelated third-party sellers, approximately 4,000 net acres in the Permian Basin for an aggregate purchase price of approximately $220 million in cash, including customary closing adjustments.

2022 Divestiture Activity

In October 2022, we 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. We used the net proceeds from this transaction towards debt reduction.

See Note 4—Acquisitions and Divestitures and Note 16—Subsequent Events of the notes to the consolidated financial statements included elsewhere in this Annual Report for additional discussion of these transactions.

Commodity Prices and Certain Other Market Considerations

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 the future, extreme weather conditions and other substantially variable factors, influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2022, 2021 and 2020 the NYMEX WTI price for crude oil ranged from $(37.63) to $123.70 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $9.68 per MMBtu, with seven-year highs reached in 2022. The war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and recent measures to combat persistent inflation contributed to economic and pricing volatility during 2022 and may continue to impact prices in 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. However, pricing may remain volatile during of 2023.

Outlook

After giving effect for the recently completed the FireBird and Lario acquisitions, we expect to hold our pro forma oil production levels essentially flat in 2023. During 2022, we had total capital expenditures of $1.9 billion, which was consistent with our guidance presented in November of 2022. During the second quarter of 2022, we announced an increase to our quarterly return of capital commitment to at least 75% of our free cash flow beginning in the third quarter of 2022.

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Accordingly, we are utilizing our free cash flow to meet our quarterly return of capital commitment and for debt repayment rather than expanding our drilling program. During 2022, we continued to pay down debt and believe we have a strong balance sheet that can withstand another down cycle. We are focused on maintaining high cash margins and a low-cost structure to drive an increasing return on capital and operational excellence, and to mitigate inflationary pressures through improvements and efficiencies in our drilling and completion programs. Going forward, we intend to continue to remain flexible and use a combination of our growing and sustainable base dividend, variable dividend and opportunistic share repurchase program to generate the highest value proposition for our stockholders.

In the Midland Basin, we continued 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.

In the Delaware Basin, we continued to target the Wolfcamp and Bone Spring formations across our primary development areas located in Pecos, Reeves and Ward counties. Collectively, the Delaware Basin accounted for approximately 15% of our total development in 2022, and we expect a similar portion of our total development to be focused in these areas in 2023.

As of December 31, 2022, we were operating 19 drilling rigs and four completion crews and currently intend to operate between 13 and 19 drilling rigs and between four and seven completion crews in 2023 on average across our current acreage position in the Midland and Delaware Basins.

Additionally, in the first quarter of 2023, we announced a target to sell at least $1.0 billion of non-core assets by year-end 2023, up from the previously announced target of $500 million.

Environmental Responsibility Initiatives and Highlights

In September 2022, we announced our medium-term goal to reduce Scope 1 and Scope 2 GHG intensity reduction by at least 50% from our 2020 level by 2030 and a 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, 2022, we had installed CEMS that cover approximately 85% 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 2022, we flared approximately 2.3% of our gross natural gas production and sourced approximately 41% 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 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. We have also increased the weighting of ESG metrics from 20% to 25% in our annual short-term incentive compensation plan to motivate our executives and our employees to advance our environmental responsibility goals.

2023 Capital Budget

We have currently budgeted 2023 total capital spend of $2.50 billion to $2.70 billion. 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.

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Results of Operations

The following discussion focuses primarily on a comparison of the results of operations between the years ended December 31, 2022 and 2021. For a discussion of the results of operations for the year ended December 31, 2021 as compared to the year ended December 31, 2020, 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, 2021 (filed with the SEC on February 24, 2022), 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:

(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.

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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, 2022 and 2021:

See “Items 1 and 2. Business and Properties— Oil and Natural Gas Production Prices and Production Costs” for further discussion of production by basin.

Comparison of the Years Ended December 31, 2022 and 2021

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues increased by approximately $2.8 billion, or 42%, to $9.6 billion for the year ended December 31, 2022 from $6.7 billion for the year ended December 31, 2021. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $2.7 billion of the total increase. The remainder of the overall change is due to a 3% increase in combined volumes sold.

Higher commodity prices during 2022 compared to 2021 primarily reflect the increase in demand for oil due to economic recovery from the COVID-19 pandemic and other macroeconomic factors such as the war in Ukraine as discussed in “—Commodity Prices and Certain Other Market Considerations” above. The increase in production for the year ended December 31, 2022 compared to the same period in 2021 resulted primarily from recognizing a full year of production in the current period associated with production from the Guidon Acquisition and the QEP Merger, which occurred late in the first quarter 2021, and new well additions between periods.

Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2022 and 2021:

Lease operating expenses for the year ended December 31, 2022 as compared to the year ended December 31, 2021 increased by $87 million, or $0.51 per BOE, primarily due to an overall increase in utility and service costs driven by continued inflation. As a result of inflationary pressures, we expect our total lease operating expenses in 2023 to range from approximately $785 million to $883 million.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2022 and 2021:

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In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the year ended December 31, 2022 compared to the same period in 2021.

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, 2022 compared to the year ended December 31, 2021 increased by $52 million primarily due to higher overall valuations resulting from an increase in commodity prices between valuation periods.

We expect production and ad valorem taxes to be approximately 7% to 8% of oil, natural gas and natural gas liquids revenue during 2023.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the years ended December 31, 2022 and 2021:

The increase in gathering and transportation expenses for the year ended December 31, 2022 compared to the same period in 2021 is primarily due to the increase in production between periods as well as an overall increase in the cost per BOE. The increase in cost is largely attributable to higher third-party gas gathering expenses of approximately $30 million related to gathering fees incurred after we divested certain gas gathering assets during the fourth quarter of 2021, and minimum volume commitment fees of approximately $8 million. The remaining increase primarily related to rate escalations on our gathering and transportation contracts.

We expect gathering and transportation expenses to range from approximately $283 million to $321 million in 2023.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2022 and 2021:

The increase in depletion of proved oil and natural gas properties of $48 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021 resulted largely from higher production volumes and a slight increase in the average depletion rate.

Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the year ended December 31, 2022. In connection with the QEP Merger and the Guidon Acquisition, we recorded the oil and natural gas properties acquired at fair value. Pursuant to SEC guidance, we determined 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, we requested and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. 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 we not received the waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded in the first quarter of 2021. 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.

Impairment charges affect our results of operations but do not reduce our cash flow. See Note 5—Property and Equipment of the notes to the consolidated financial statements included elsewhere in this Annual Report and “— Critical Accounting Estimates” for further details regarding factors that impact the impairment of oil and natural gas properties.

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General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2022 and 2021:

Total general and administrative expenses for the year ended December 31, 2022 were consistent with the same period in 2021 and there were no significant individual contributing factors to the change between periods.

We expect cash general and administrative expenses to range from approximately $102 million to $128 million in 2023, and non-cash stock-based compensation to range from approximately $63 million to $80 million in 2023.

Merger and Integration Expense. The following table shows merger and integration expense for the years ended December 31, 2022 and 2021:

Total merger and integration expense for the year ended December 31, 2022 relates to banking, legal and advisory fees of $11 million for the Rattler Merger, $2 million for the FireBird Acquisition, and $1 million for the Lario Acquisition.

Merger and integration expense for the year ended December 31, 2021 includes $69 million in costs incurred for the QEP Merger and $9 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $39 million in severance costs and $30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory and legal fees. See Note 4—Acquisitions and Divestitures of the notes to the consolidated financial statements included elsewhere in this Annual Report for further details regarding the QEP Merger and the Guidon 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, 2022 and 2021:

(1)The year ended December 31, 2022 includes $57 million in losses related to interest rate swaps.

(2)The year ended December 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $138 million.

(3)The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million and cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

At December 31, 2022, we have a short-term derivative asset of $132 million, a long-term derivative asset of $23 million, a short-term derivative liability due in 2023 of $47 million and a long-term derivative liability due in 2024 of $148 million.

See Note 12—Derivatives of the notes to the consolidated financial statements included elsewhere in this Annual report for further details regarding our derivative instruments and interest rate swaps.

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Other Income (Expense). The following table shows other income and expenses for the year ended December 31, 2022 and 2021:

The decrease in net interest expense for the year ended December 31, 2022 compared to the same period in 2021, primarily reflects a $36 million increase in capitalized interest costs, which reduce interest expense, and a $26 million decrease in interest expense on our senior notes due largely to redemptions and repurchases of principal between the periods. These reductions were partially offset by an $18 million increase in interest expense on our revolving credit facility. We expect interest expense to range from approximately $204 million to $225 million in 2023.

Gain (loss) on extinguishment of debt reflects the difference between the carrying value and reacquisition price for the repurchases and redemptions of various senior notes during the 2022 and 2021 periods.

See Note 8—Debt of the notes to the consolidated financial statements included elsewhere in this Annual report for further details outstanding borrowings, interest expense and gain (loss) on extinguishment of debt.

The increase in income from our equity investments primarily reflects higher capacity utilization and price realizations for our midstream investees in 2022 compared to 2021, as well as increase of $38 million in income from our investment in an interconnected gas gathering system in the Midland Basin, which was acquired in the fourth quarter of 2021.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2022 and 2021:

The change in our income tax provision for the year ended December 31, 2022 compared to the same period in 2021 was primarily due to the increase in pre-tax income which resulted largely from the changes in revenues from oil, natural gas and natural gas liquids. See Note 11—Income Taxes of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity include cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties, payments to retire debt and interest expense on debt, dividends and share repurchases, and income taxes, At December 31, 2022, we had approximately $1.8 billion of liquidity consisting of $157.0 million in cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2023 is $2.50 billion to $2.70 billion.

Future cash flows are subject to a number of variables, including the level of oil and natural gas production, volatility of commodity prices, and 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” 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

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estimated future crude oil and natural gas production through the end of 2023 as discussed further in Note 12—Derivatives of the notes to the consolidated financial statements included elsewhere in this Annual Report and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. 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.

Cash Flow

Our cash flows for the years ended December 31, 2022 and 2021 are presented below:

Operating Activities

The increase in operating cash flows for the year ended December 31, 2022 compared to the same period in 2021 primarily resulted from (i) an increase of $2.8 billion in our total revenue, (ii) a decrease of $397 million in net cash paid on settlements of derivative contracts, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections are made on accounts receivable and payments are made on accounts payable and accrued liabilities. These net cash inflows were partially offset by (i) a change of $856 million in cash paid for taxes due to making payments of $718 million in 2022 compared to receiving net refunds of $138 million in federal taxes under the 2020 CARES act in 2021, and (ii) an increase in our cash operating expenses of approximately $266 million. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities was $3.3 billion compared to $1.5 billion for the years ended December 31, 2022 and 2021, respectively. The majority of our net cash used for investing activities during the year ended December 31, 2022 was for the purchase and development of oil and natural gas properties and related assets, including the FireBird Acquisition. These expenditures were partially offset by proceeds from the sale of certain non-core Delaware Basin assets and other assets discussed in Note 4—Acquisitions and Divestitures.

The majority of our net cash used in investing activities during the year ended December 31, 2021 was for the purchase and development of oil and natural gas properties and related assets, including the acquisition of certain leasehold interests as part of the Guidon Acquisition. These expenditures were partially offset by proceeds from the divestiture of our Williston Basin assets, leasehold acreage and other gathering assets discussed in Note 4—Acquisitions and Divestitures. Our capital expenditures for each period are discussed further below.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

For further discussion regarding our development program, please see the section entitled “Item 1 and 2. Business and Properties—Wells Drilled and Completed in 2022.”

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Financing Activities

Net cash used in financing activities for the year ended December 31, 2022 was $3.5 billion compared to net cash used in financing activities for the year ended December 31, 2021 of $1.8 billion. During the year ended December 31, 2022, the amount used in financing activities 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 borrowings under our and our subsidiaries’ credit facilities, net of repayments.

Net cash used in financing activities for the year ended December 31, 2021 was primarily attributable to (i) $3.2 billion paid for the retirement of outstanding principal on certain senior notes, as well as $178 million of additional premiums paid in connection with the repurchases, (ii) $525 million of repurchases as part of the share and unit repurchase programs, (iii) $312 million of dividends paid to stockholders, and (iv) $112 million in distributions to non-controlling interest. The cash outflows were partially offset by (i) $2.2 billion in proceeds our senior notes issued in 2021, (ii) $313 million of borrowings under our and our subsidiaries’ credit facilities, net of repayments and (iii) $22 million in net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element.

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. 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 our business and 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. Continued prolonged volatility in the capital, financial and/or credit markets due to the war in Ukraine, the COVID-19 pandemic and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and Senior Notes

As of December 31, 2022, the maximum credit amount available under our credit agreement was $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion), with no outstanding borrowings and an aggregate of $3 million in outstanding letters of credit which reduce available borrowings on a dollar for dollar basis. During the second quarter of 2022, we extended the maturity date on our credit agreement by one year to June 2, 2027, and may further extend it by two one-year extensions pursuant to the terms set forth in the credit agreement.

During the year ended December 31, 2022, we issued $2.5 billion in principal amount of senior notes with extended maturity dates ranging from 2033 through 2053.

See Note 8—Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of our revolving credit facility and senior notes.

Viper’s Revolving Credit Facility

Viper’s credit agreement, as amended to date, matures on June 2, 2025 and provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580 million as of December 31, 2022, although Viper had an elected commitment amount of $500 million, based on Viper LLC’s oil and natural gas reserves and other factors. At December 31, 2022, there were $152 million of outstanding borrowings and $348 million available for future borrowings under Viper’s credit agreement.

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Capital Requirements

In addition to future operating expenses and working capital commitments discussed in “—Results of Operations”, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit agreements and senior notes, (ii) payments of other contractual obligations, (iii) cash commitments for dividends and share repurchases, and (iv) income taxes.

2023 Capital Spending Plan

Our board of directors approved a 2023 capital budget for drilling, midstream and infrastructure of $2.50 billion to $2.70 billion. We estimate that, of these expenditures, approximately:

•$2.25 billion to $2.41 billion will be spent primarily on drilling 325 to 345 gross (293 to 311 net) horizontal wells and completing 330 to 350 gross (297 to 315 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,500 feet;

•$80 million to $100 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$170 million to $190 million will be spent on infrastructure and environmental expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount and timing of our 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. 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.

Payments of Principal and Interest on Senior Notes

During the year ended December 31, 2022 we retired $2.4 billion in principal amount of our then-outstanding senior notes with a portion of the net proceeds from our senior notes offerings completed in March and October of 2022, cash on hand and borrowings under Viper’s revolving credit facilities, as applicable, as discussed further in Note 8—Debt of the notes to the consolidated financial statements included elsewhere in this Annual Report.

At December 31, 2022, we have total principal payments due on our outstanding senior notes, including those of Viper, of $10 million in 2023, $1.2 billion cumulatively in the years 2026 and 2027, and $5.0 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $265 million in 2023, $530 million cumulatively in the years from 2024 through 2025, $504 million cumulatively in the years from 2026 and 2027, and $2.9 billion cumulatively between 2028 and 2053.

Other Contractual Obligations and Commitments

At December 31, 2022, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $856 million, (ii) asset retirement obligations totaling $347 million, (iii) electronic fracturing fleet and related power generation services commitments totaling $140 million and (iv) minimum purchase commitments for quantities of sand used in our drilling operations totaling $91 million. We expect to make aggregate payments of approximately $166 million for these commitments during 2023. See Note 6—Asset Retirement Obligations and Note 15—Commitments and Contingencies of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of these and other contractual obligations and commitments.

Dividends and Share Repurchases

In addition to our base dividend program, in the first quarter of 2022 we initiated a variable dividend strategy whereby we may pay a quarterly variable dividend based on the prior quarter’s free cash flow remaining after the payment of the base dividend. Beginning in the third quarter of 2022, our board of directors approved an increase to this return of capital commitment to at least 75% of free cash flow. On February 16, 2023, our board of directors approved an increase to the

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Company’s annual base dividend to $3.20 per share. We have declared a base plus variable cash dividend for the fourth quarter of 2022 of $2.95 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. 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 properties across periods on a consistent basis.

Future base and variable 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 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 variable 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 the our control, including commodity prices.

As of February 17, 2023, we have repurchased 13.2 million shares of our common stock for a total cost of $1.6 billion since the inception of the repurchase program. We intend to continue to opportunistically purchase shares under this repurchase program with available funds primarily from cash flow from operations and liquidity 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 of the notes to the consolidated financial statements included elsewhere in this report for further discussion of the repurchase program.

Income Taxes

We expect our cash tax rate to be 10% to 15% of pre-tax income for the year ended December 31, 2023. See Note 11—Income Taxes of the notes to the consolidated financial statements included elsewhere in this Annual report for further discussion of our income taxes.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.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 three main credit rating agencies are as follows:

•Standard and Poor’s Global Ratings Services (BBB-);

•Fitch Investor Services (BBB); and

•Moody’s Investor Services (Baa2).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under the 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, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

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The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur 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 determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, 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 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 or financial position had the guarantor subsidiary operated as an independent entity.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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 and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our board of directors.

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Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural 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 estimation of proved reserves to be a critical accounting estimate.

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. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers, as of December 31, 2022 and prepared by Ryder Scott as of December 31, 2021 and 2020. 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, 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 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 depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately $102 million, or 1% of the change in the standardized measure of our total reserves from December 31, 2021 to December 31, 2022. No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2022 and 2021; however, a material impairment was recorded during the year ended December 31, 2020 as discussed further in Note 5—Property and Equipment of the notes to the consolidated financial statements included elsewhere in this Annual Report. Due to an increase in the historical 12-month average trailing SEC prices for oil and natural throughout 2021 and into 2022, we are not currently projecting a full cost ceiling impairment in the first quarter of 2023.

Additionally, 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 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: intent of the operator to drill, remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. At December 31, 2022, our unevaluated properties totaled $8.4 billion, which consisted of 236,253 net undeveloped leasehold acres with approximately 465 net acres set to expire in 2023. We did not record any impairment on our unevaluated properties during the year ended December 31, 2022, but any such future impairment could potentially be material to our consolidated financial statements.

Commodity Derivatives

From time to time, we use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise 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 hedges 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 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.

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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 for additional sensitivity analysis of our open derivative positions at December 31, 2022.

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 estimates 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 market valuation approaches depending on the quality of information 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 oil 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 a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. See Note 4—Acquisitions and Divestitures of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the estimated fair value of assets acquired and liabilities assumed in the QEP Merger, Guidon Acquisition and FireBird Acquisition, including any significant changes in these estimates from the date of acquisition.

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 the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial 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 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. 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 2022, 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 an income tax benefit of $50 million 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. As of December 31, 2022, Viper had a deferred tax asset of $148 million offset by an allowance of $98

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million. The valuation allowance remains in place based on the uncertainty of future events, including Viper’s ability to generate future taxable income in excess of special allocations to be made to Diamondback, and management considered this and other factors in evaluating the realizability of Viper’s deferred tax assets. 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 record 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 IRC Section 382 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, 2022, 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, 2022, our uncertain tax positions were insignificant, 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

See Note 2—Summary of Significant Accounting Policies of the notes to the consolidated financial statements included elsewhere in this Annual Report for recent accounting pronouncements not yet adopted, if any.

Off-Balance Sheet Arrangements

See Note 15—Commitments and Contingencies of the notes to the consolidated financial statements included elsewhere in this Annual Report for a discussion of our significant commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.

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 this Annual 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 Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. We operate in 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 (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

We operate under a strategic approach that focuses predominantly on enhancing return through our low-cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. We are also committed to delivering results in a socially and environmentally responsible manner.

2021 Financial and Operating Highlights

•We recorded net income of $2.2 billion for the year ended December 31, 2021.

•Our average production was 137,002 MBOE/d during the year ended December 31, 2021.

•During the year ended December 31, 2021, we drilled 175 gross horizontal wells in the Midland Basin and 41 gross horizontal wells in the Delaware Basin.

•We turned 275 gross operated horizontal wells (including 207 in the Midland Basin and 64 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $1.5 billion during the year ended December 31, 2021.

•The average lateral length for the wells completed during the year ended December 31, 2021 was 10,602 feet.

•As of December 31, 2021, we had approximately 445,848 net acres, which primarily consisted of approximately 265,562 net acres in the Midland Basin and approximately 148,588 net acres in the Delaware Basin. As of December 31, 2021, we had an estimated 9,314 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 930,871 gross acres and 27,027 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 54% of these net royalty acres are operated by us.

•Our cash operating costs for the year ended December 31, 2021 were $9.46 per BOE, including lease operating expenses of $4.12 per BOE, cash general and administrative expenses of $0.69 per BOE and production and ad valorem taxes and gathering and transportation expenses of 4.65 per BOE.

2021 Transactions and Recent Developments

2021 Acquisition Activity and Recent Transactions

On February 26, 2021, we completed 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.

On March 17, 2021, we completed the QEP Merger. The addition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the merger agreement, we issued approximately 12.12 million shares of our common stock to the former QEP stockholders, with a total value of approximately $987 million on the closing date.

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On October 1, 2021, Viper completed the acquisition of certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) which included certain mineral and royalty interests for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The cash portion of the purchase price was funded through a combination of cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.

On October 5, 2021, Rattler and a private affiliate of an investment fund formed a joint venture entity, Remuda Midstream Holdings LLC (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 LLC (“WTG Midstream”).

2021 Divestiture Activity

On June 3, 2021 and June 7, 2021, respectively, we 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. We used our net proceeds from these transactions toward debt reduction.

On October 21, 2021, we completed the divestiture of our Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres acquired in the QEP Merger, for net cash proceeds of approximately $586 million after customary closing adjustments. We used our net proceeds from this transaction toward debt reduction.

On November 1, 2021, we completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, which we refer to as Brazos, for net cash proceeds of approximately $54 million, after customary closing adjustments.

On December 1, 2021, we completed the sale of certain water midstream assets with a carrying value of approximately $160 million to Rattler in exchange for cash proceeds of approximately $160 million.

On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for net cash proceeds of approximately $83 million at closing, after customary closing adjustments, and an aggregate of $10 million in contingent payments.

See Note 4—Acquisitions and Divestitures for additional discussion of these transactions.

Debt Transactions

Issuances of Notes

On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the redemption of other senior notes outstanding as discussed further below.

Redemption of Notes

The net proceeds from the March 2021 Notes discussed above were primarily used to fund the repurchase of $1.65 billion in fair value carrying amount of the QEP Notes that remained outstanding at the effective time of the QEP Merger for total cash consideration of $1.7 billion, and $368 million principal amount of 2025 Senior Notes, for total cash consideration of $381 million. Giving effect to the repurchase of the 2023 Notes discussed below, these refinancing transactions are expected to result in an estimated annual interest cost savings of approximately $40 million in addition to an estimated $60 to $80 million of previously announced expected annual cost synergies from the QEP Merger.

In June 2021, we redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen Corporation (“Energen”).

In August 2021 we redeemed the remaining $432 million principal amount of our outstanding 5.375% 2025 Senior Notes at a redemption price equal to 102.688% of the principal amount plus accrued interest. We funded the redemption with cash on hand and borrowings under our revolving credit facility.

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On November 1, 2021, we redeemed the aggregate $650 million principal amount of our outstanding 2023 Notes with the proceeds received from the divestiture of our Williston Basin assets and cash on hand.

For additional discussion of our 2021 debt transactions and the amendment to the second amended and restated credit facility, see Note 11—Debt.

Fourth Quarter 2021 Dividend Declaration and Increase

On February 18, 2022, our board of directors declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to our stockholders of record at the close of business on March 4, 2022, representing a 20% increase per share from the previously paid quarterly dividend.

Stock and Unit Repurchase Programs

During the year ended December 31, 2021, we repurchased approximately $431 million of Diamondback common stock, and as of December 31, 2021, $1.6 billion remained available for future purchases under our common stock repurchase program.

During the year ended December 31, 2021, Viper repurchased approximately $46 million of common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program.

During the year ended December 31, 2021, Rattler repurchased approximately $48 million of common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.

See “—Liquidity and Capital Resources” below for additional discussion.

COVID-19 and Effects on Commodity Prices

In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the COVID-19 pandemic. Demand for oil and natural gas increased during 2021, as many restrictions on conducting business implemented in response to the COVID-19 pandemic were lifted due to improved treatments and availability of vaccinations in the U.S. and globally. As a result, oil and natural gas market prices have improved during 2021 in response to the increase in demand. During 2021 and 2020, the posted price for West Texas intermediate light sweet crude oil, or NYMEX WTI, has ranged from $(37.63) to $84.65 Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.48 to $6.31 per MMBtu. On January 18, 2022, the closing NYMEX WTI price for crude oil was $85.43 per Bbl and the closing NYMEX Henry Hub price of natural gas was $4.28 per MMBtu. The emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant, however, contributed to economic and pricing volatility as industry and market participants evaluated industry conditions and production outlook. Further, on January 4, 2021, OPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced in August of 2021) of gradual monthly output increases in February 2022, raising its output target by 400,000 Bbls per day, which is expected to further boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 million Bbls per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in commodity prices or demand for crude oil.

Despite the recovery in commodity prices and rising demand, we kept our production relatively flat during 2021, using excess cash flow for debt repayment and/or return to our stockholders rather than expanding our drilling program.

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Outlook

During 2021, we continued building on our execution track record, generating free cash flow while keeping capital costs under control, and our efficiency gains, particularly in the Midland Basin drilling and completion programs, were able to mitigate certain inflationary pressures on well costs and led to a total capital expenditure amount of $1.5 billion down 11% from our guidance presented in April of 2021. We expect to continue to build on these operational efficiencies by controlling the variable portion of our operating and capital costs, which we believe will help mitigate the inflationary pressures seen across our business. We remain committed to capital discipline by maintaining flat oil production in 2022 and expect to maintain our best-in-class capital efficiency and cost structure. We expect to be in a position to continue to deliver on the recently announced enhanced capital return program, where we expect to distribute at least 50% of our quarterly free cash flow to our stockholders. Our capital return program is currently focused on our sustainable and growing dividend and a combination of stock repurchases and variable dividends. We expect to remain flexible on returning capital to our stockholders, depending on which method our board of directors believes presents the best return of capital to our stockholders at the relevant time.

In the Midland Basin, we continued 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.

In the Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2022, we expect to focus development on these areas.

As of December 31, 2021, we were operating 10 drilling rigs and four completion crews and currently intend to operate between 10 and 12 drilling rigs and between three and four completion crews in 2022 on average across our current acreage position in the Midland and Delaware Basins.

Environmental Responsibility Initiatives and Highlights

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 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 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. We have also increased the weighting of ESG metrics in our annual short-term incentive compensation plan to motivate our executives to advance our environmental responsibility goals.

In September 2021, we announced our long-term goal to end routine flaring by 2025 and a long-term target to source over 65% of our water used for drilling and completion operations from recycled sources by 2025. With respect to flaring, we flared 1.55% of our gross natural gas production in the fourth quarter of 2021. For the full year ended 2021, we flared 1.45% of our gross natural gas production, down 26% from 2020.

2022 Capital Budget

We have currently budgeted 2022 total capital spend of $1.75 billion to $1.90 billion. 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.

Results of Operations

The following discussion focuses primarily on a comparison of the results of operations between the years ended December 31, 2021 and 2020. The midstream operations segment’s revenues and operating expenses were not significant to our consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019. .For a discussion of the results of operations for the year ended December 31, 2020 as compared to the year ended December 31, 2019, 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, 2020 (filed with the SEC on February 25, 2021), which is incorporated in this report by reference from such prior report on Form 10-K.

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

(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 tables provides information on the mix of our production for the years ended December 31, 2021 and 2020:

Comparison of the Years Ended December 31, 2021 and 2020

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

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Our oil, natural gas and natural gas liquids revenues increased by approximately $4.0 billion, or 145%, to $6.7 billion for the year ended December 31, 2021 from $2.8 billion for the year ended December 31, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $3.3 billion of the total increase. The remainder of the overall change is due to a 25% increase in combined volumes sold.

Higher commodity prices during 2021 compared to 2020 primarily reflect a recovery from historically low prices experienced in 2020 due to the COVID-19 pandemic as discussed in “—2021 Transactions and Recent Developments” above. The increase in production for 2021 compared to 2020 resulted primarily from the Guidon Acquisition and QEP Merger during the first quarter of 2021 and an overall recovery in our drilling and production activities after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic. We expect to hold our oil production levels flat during 2022.

Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2021 and 2020:

Lease operating expenses for the year ended December 31, 2021 as compared to the year ended December 31, 2020 increased by $140 million, or $0.25 per BOE, primarily due to an increase in production between periods driven by the Guidon Acquisition and the QEP Merger in the first quarter of 2021. The increase on a per BOE basis is primarily related to the Williston Basin assets acquired in the QEP Merger which had higher lease operating costs per BOE on average than our historical properties. We completed the divestiture of the Williston Basin properties in October 2021.

Including the impact of our acquisition and divestiture activity in 2021 and future production plans, our total lease operating expenses in 2022 are expected to range from approximately $539 million to $618 million.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2021 and 2020:

In general, production taxes are directly related to production revenues. Production taxes for the year ended December 31, 2021 increased by $214 million, or $1.32 per BOE. The increase in production taxes is attributable to an increase in commodity prices, as well as an increase in overall production due to assets acquired in 2021. The current year increase on a per BOE basis is primarily driven by an increase in current year commodity prices. Production taxes as a percentage of production revenues increased for the year ended December 31, 2021 compared to the year ended December 31, 2020 due primarily to the acquired Williston Basin properties which have a higher production tax rate than our other properties. We completed the divestiture of the Williston Basin properties in October 2021.

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, 2021 as compared to the year ended December 31, 2020 increased by $16 million primarily due to additional properties acquired in the Guidon Acquisition and the QEP Merger.

We expect production taxes to be approximately between 7% and 8% of oil, natural gas and natural gas liquids revenue during 2022.

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Gathering and Transportation Expense. The following table shows gathering and transportation expense for the year ended December 31, 2021 and 2020:

For the year ended December 31, 2021, the increase for gathering and transportation expenses are primarily attributable to the increase in production between periods. The current year increase on a per BOE basis is primarily driven by production added from the assets acquired in the QEP Merger which, in general, had higher average gathering and transportation costs per BOE than our historical properties, particularly those QEP assets located in the Williston Basin, which we divested in the fourth quarter of 2021. After giving effect to the 2021 acquisition and divestiture activities, we expect gathering and transportation expenses to range from approximately $212 to $243 million in 2022.

Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2021 and 2020:

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. In the fourth quarter of 2021, we and Rattler divested our natural gas gathering and transportation assets. Midstream services expense for the year ended December 31, 2021 as compared to the year ended December 31, 2020 decreased by $16 million primarily due to decreased maintenance costs, partially offset by increased fees for use of third party disposal systems.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2021 and 2020:

The decrease in depletion of proved oil and natural gas properties of $40 million for the year ended December 31, 2021 as compared to the year ended December 31, 2020 resulted primarily from a reduction in the average depletion rate partially offset by increased production in 2021. The decline in rate resulted primarily from higher SEC oil prices utilized in the reserve calculations during 2021, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.

Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the year ended December 31, 2021. In connection with the QEP Merger and the Guidon Acquisition, we recorded the oil and natural gas properties acquired at fair value. Pursuant to SEC guidance, we determined 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, we requested and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. 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 we not received the waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded in the first quarter of 2021. 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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As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the year ended December 31, 2020 of $6.0 billion which is included in accumulated depletion, depreciation, amortization and impairment on our consolidated balance sheet. Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 8—Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties.

General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2021 and 2020:

General and administrative expenses for the year ended December 31, 2021 as compared to the year ended December 31, 2020 increased by $58 million primarily due to additional payroll and other employee driven costs of $32 million related to the QEP Merger and the Guidon Acquisition as well as $10 million of additional expense related to the implementation of a new enterprise resource planning system. Additionally, equity compensation for the year ended December 31, 2021 increased by $14 million compared to the same period in 2020.

We expect cash general and administrative expenses to range from approximately $87 million to $110 million in 2022, and non-cash stock-based compensation to range from approximately $54 million to $69 million in 2022.

Merger and Integration Expense. The following table shows merger and integration expense for the years ended December 31, 2021 and 2020:

Total merger and integration expense for the year ended December 31, 2021 includes $69 million in costs incurred for the QEP Merger and $9 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $39 million in severance costs and $30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory and legal fees. See Note 4—Acquisitions and Divestitures for further details regarding the QEP Merger and the Guidon Acquisition.

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Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2021 and 2020:

Net interest expense increased by $2 million for the year ended December 31, 2021 as compared to the year ended December 31, 2020. This increase primarily consisted of (i) $47 million in interest costs on the newly issued March 2021 Notes (ii) $25 million due to incurring a full year of interest expense in 2021 related to our May 2020 Notes and Rattler’s 5.625% Senior Notes due 2025, and (iii) to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021. These increases were partially offset by (i) $33 million in additional capitalized interest costs, (ii) interest cost savings of $23 million on the repurchases of our 2025 Senior Notes in March 2021 and August 2021, (iii) $8 million on the repurchase of our 4.625% senior notes of Energen (iv) a $9 million reduction in borrowings under our revolving credit agreements during 2021, and (v) to a lesser extent, interest savings on the repurchase of our 2023 Notes in November 2021. We expect interest expense, net of interest income to range from approximately $148 million to $178 million in 2022. See Note 11—Debt for further details regarding outstanding borrowings and interest expense.

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, 2021 and 2020:

(1)The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.

(2)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.

(3)The year ended December 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

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 commodity 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.” As part of the QEP Merger, we received by novation from QEP certain derivative instruments which are included on our balance sheet as of December 31, 2021.

We have designated certain of our interest rate swaps as fair value hedges for accounting purposes. As a result, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and no gain or loss is recognized due to hedge effectiveness. Changes in fair value are recorded as an adjustment to the carrying value of the 2029 Notes in the consolidated balance sheet. Beginning on December 1, 2021, we began recording semi-annual cash settlements of these interest rate swaps in interest expense in the consolidated statements of operations.

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At December 31, 2021, we have a short-term derivative asset of $13 million, a long-term derivative asset of $4 million, a short-term derivative liability due in 2022 of $174 million and a long-term derivative liability due in 2023 of $29 million.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2021 and 2020:

The changes in our income tax provision for the year ended December 31, 2021 compared to the same period in 2020 were primarily due to the increase in pre-tax income for the year ended December 31, 2021.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity include cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. At December 31, 2021, we had approximately $2.2 billion of liquidity consisting of $0.7 billion in cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2022 is $1.75 billion to $1.90 billion. Further, we have $45 million of senior notes maturities in the next 12 months.

Our working capital requirements are supported by our cash and cash equivalents and our 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. Because of the alternatives available to us as discussed above, 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 funding requirements including our capital spending programs, dividend payments, debt service obligations and repayment of debt maturities, stock repurchase program and other amounts that may ultimately be paid in connection with contingencies.

Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, hedging a portion of our estimated future crude oil and natural gas production through the end of 2023 as discussed further in Note 15—Derivatives and Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. 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.

As we pursue our business and 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. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although the Company expects that its sources of funding will be adequate to fund its short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

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Cash Flow

Our cash flows for the years ended December 31, 2021 and 2020 are presented below:

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. 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 Item 1A. “Risk Factors” above.

The increase in operating cash flows for the year ended December 31, 2021 compared to the same period in 2020 primarily resulted from (i) an increase of $4.0 billion in our total revenues, and (ii) receipt of $152 million in refunds of income taxes receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the CARES Act in 2020. These net cash inflows were partially offset by (i) a reduction of $1.5 billion due to making net cash payments of $1.2 billion on our derivative contracts in the year ended December 31, 2021 compared to receiving net cash of $250 million on our derivative contracts in the year ended December 31, 2020, (ii) an increase in our cash operating expenses of approximately $550 million primarily due to the QEP Merger and the Guidon Acquisition, and (iii) other working capital changes, primarily due to recording increases in accounts receivable, accounts payable and accrued capital expenditure activity stemming from the QEP Merger and the Guidon Acquisition in 2021. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities was $1.5 billion compared to $2.1 billion for the years ended December 31, 2021 and 2020, respectively. The majority of our net cash used for investing activities during the year ended December 31, 2021 was for the purchase and development of oil and natural gas properties and related assets, including the acquisition of certain leasehold interests as part of the Guidon Acquisition. These expenditures were partially offset by proceeds from the sale of our Williston Basin assets, leasehold acreage and other gathering assets discussed in Note 4—Acquisitions and Divestitures.

The majority of our net cash used in investing activities during the year ended December 31, 2020 was for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below.

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Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

(1) During the year ended December 31, 2021, in conjunction with our development program, we drilled 216 gross (203 net) operated horizontal wells, of which 175 gross (165 net) wells were in the Midland Basin and 41 gross (38 net) wells were in the Delaware Basin, and turned 275 gross (258 net) operated horizontal wells to production, of which 207 gross (194 net) were in the Midland Basin and 64 gross (61 net) wells were in the Delaware Basin.

(2) During the year ended December 31, 2020, in conjunction with our development program, we drilled 208 gross (195 net) operated horizontal wells, of which 133 gross (125 net) wells were in the Midland Basin and 75 gross (70 net) wells were in the Delaware Basin, and turned 171 gross (159 net) operated horizontal wells to production, of which 93 gross (85 net) were in the Midland Basin and 78 gross (74 net) wells were in the Delaware Basin.

Financing Activities

Net cash used in financing activities for the year ended December 31, 2021 was $1.8 billion compared to net cash used in financing activities for the year ended December 31, 2020 of $37 million. During the year ended December 31, 2021, the amount used in financing activities was primarily attributable to (i) $3.2 billion paid for the repurchase of outstanding principal on certain senior notes as discussed in “—Repurchases of Notes” below, as well as $178 million of additional premiums paid in connection with the repurchases, (ii) $525 million of repurchases as part of the share and unit repurchase programs, (iii) $312 million of dividends paid to stockholders, and (iv) $112 million in distributions to non-controlling interest. The cash outflows were partially offset by (i) $2.2 billion in proceeds from the March 2021 Notes, (ii) $313 million of borrowings under our and our subsidiaries’ credit facilities, net of repayments and (iii) $22 million in net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element.

Net cash used in financing activities for the year ended December 31, 2020 was primarily attributable to $348 million of repayments, net of borrowings, on our credit facilities, $239 million in aggregate repayments on the Energen Notes and Viper Notes, $236 million in dividends paid to stockholders, $98 million of share repurchases as part of our stock repurchase program, and $93 million in distributions to non-controlling interest. These cash outlays were partially offset by net proceeds of $997 million from the issuance of the May 2020 Notes and the Rattler Notes during 2020.

Capital Resources

Revolving Credit Facilities and Other Debt Instruments

As of December 31, 2021, our debt, including the debt of Viper and Rattler, consists of approximately $6.2 billion in aggregate outstanding principal amount of senior notes, $499 million in aggregate outstanding borrowings under revolving credit facilities and $58 million in outstanding amounts due under our DrillCo Agreement.

At December 31, 2021, we have total principal payments due on our outstanding senior notes, including those of Viper and Rattler, of $45 million in 2022, $1.2 billion cumulatively in the years 2023 through 2024, $2.1 billion cumulatively in the years 2025 and 2026, and $3.4 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $177 million in 2022, $371 million in the years from 2023 through 2024, $277 million in the years from 2025 through 2026, and $961 million between 2027 and 2051.

On June 2, 2021, we entered into a twelfth amendment, or the Amendment, to the Second Amended and Restated Credit Agreement which, among other things, decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower, subject to obtaining additional lender commitments and satisfaction of customary conditions). As of December 31, 2021, we had no outstanding borrowings under our revolving credit facility and $1.6 billion available for future borrowings under the revolving credit facility.

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Viper’s Revolving Credit Facility

Viper’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580 million as of December 31, 2021, based on the Viper’s oil and natural gas reserves and other factors. At December 31, 2021, Viper had elected a commitment amount of $500 million on its credit agreement with $304 million of outstanding borrowings. During the year ended December 31, 2021, the weighted average interest rate on borrowings under the Operating Company’s revolving credit facility was 2.35%. Viper’s Revolving credit facility matures in 2025.

Rattler’s Revolving Credit Facility

Rattler’s credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon its election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of December 31, 2021, there was $195 million of outstanding borrowings under Rattler’s revolving credit facility. The weighted average interest rate on borrowings under the credit agreement was 1.41% for the year ended December 31, 2021. Rattler’s revolving credit facility matures in 2024.

During 2021, we issued an aggregate $2.2 billion of senior notes and redeemed $3.2 billion of senior notes outstanding.

For additional discussion of our outstanding debt as of December 31, 2021, see Note 11—Debt.

Subject to market conditions, we expect to continue to issue debt securities from time to time in the future to refinance our maturing debt. The availability, interest rate and other terms of any new borrowings will depend on the ratings assigned by credit rating agencies, among other factors.

We are currently in compliance, and expect to continue to be, with all financial maintenance covenants in our debt instruments.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.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 rating from Standard and Poor’s Global Ratings Services is BBB-. Our credit rating from Fitch Investor Services is BBB. Our credit rating from Moody’s Investor Services is Baa3. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in —Results of Operations, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of other contractual obligations and (iii) cash commitments for dividends and share repurchases as discussed below.

Based upon current oil and natural gas prices and production expectations for 2022, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through the 12-month period following the filing of this report and thereafter. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2022 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

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2022 Capital Spending Plan

Our board of directors approved a 2022 capital budget for drilling, midstream and infrastructure of $1.75 billion to $1.90 billion maintaining our annualized fourth quarter 2021 cash capital expenditure guidance presented in November of 2021. We estimate that, of these expenditures, approximately:

•$1.56 billion to $1.67 billion will be spent primarily on drilling 270 to 290 gross (248 to 267 net) horizontal wells and completing 260 to 280 gross (240 to 258 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,200 feet;

•$80 million to $100 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$110 million to $130 million will be spent on infrastructure and environmental expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount and timing of our 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. We were operating 10 drilling rigs and four completion crews at December 31, 2021 and currently intend to operate between 10 and 12 rigs and between three and four completion crews on average in 2022, as we continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. 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.

Other Contractual Obligations and Commitments

At December 31, 2021, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $878 million, (ii) asset retirement obligations totaling $171 million, and (iii) minimum purchase commitment for quantities of sand used in our drilling operations totaling $77 million. We expect to make aggregate payments of approximately $105 million for these commitments during 2022. See Note 9—Asset Retirement Obligations and Note 18—Commitments and Contingencies for further discussion of these and other contractual obligations and commitments.

Dividends and Share Repurchases

We paid common stock dividends of $312 million and $236 million during 2021 and 2020, respectively. On February 18, 2022, our board of directors declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to our stockholders of record at the close of business on March 4, 2022. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors.

In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. We repurchased approximately $431 million of our common stock under this program during the year ended December 31, 2021, and have $1.6 billion remaining for future repurchases under the repurchase program at December 31, 2021 See Note 12—Stockholders' Equity and Earnings Per Share for further discussion of the repurchase program.

Guarantor Financial Information

In connection with the merger of certain of the Company’s wholly owned subsidiaries in an internal subsidiary restructuring on June 30, 2021, Diamondback E&P became the successor borrower to Diamondback O&G LLC (“O&G”) under the credit agreement, the successor issuer of Energen’s 7.125% Medium-term Notes, Series B, due February 15, 2028 and Energen’s 7.32% Medium-term Notes, Series A, due July 28, 2022, and the sole guarantor under the indentures governing the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 2021 Notes.

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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 IG Indenture and the 2025 Indenture, 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. The 2025 Indenture was terminated in connection with the early redemption of the remaining $432 million principal amount of our 2025 Senior Notes in the third quarter of 2021.

Diamondback E&P’s guarantees of the December 2019 Notes, the May 2020 Notes and the March 2021 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, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur 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 determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, 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 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 or financial position had the guarantor subsidiary operated as an independent entity.

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Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

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 and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results 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.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural 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 estimation of proved reserves to be a critical accounting estimate.

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. Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and their associated future net cash flows. 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, 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 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 depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately $719 million, or 6% of the change in the standardized measure of our total reserves from December 31, 2020 to December 31, 2021. No impairments were recorded on for our proved oil and gas properties during the year ended December 31, 2021; however, material impairments were recorded during the years ended December 31, 2020 and 2019 as discussed further in Note 8—Property and Equipment of the notes to the consolidated financial statements included elsewhere in this Annual Report. Due to an increase in the historical 12-month average trailing SEC prices for oil and natural throughout 2021 and into 2022, we are not currently projecting a full cost ceiling impairment in the first quarter of 2022.

Additionally, 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 individual basis or as a group if properties are individually insignificant) on an annual basis for possible impairment. This assessment is subjective and includes consideration of the following factors, among others: intent of the operator to drill, remaining lease term with the current operator; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. At December 31, 2021, our unevaluated properties totaled $8 billion, which consisted of 214,151 net undeveloped leasehold acres with approximately 41,855 net acres set to expire in 2022. We did not record any impairment on our unevaluated properties during the year ended December 31, 2021, but any such future impairment could be material to our consolidated financial statements.

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Commodity Derivatives

From time to time, we use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise 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 hedges 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 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 for additional sensitivity analysis of our open derivative positions at December 31, 2021.

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 estimates 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 market valuation approaches depending on the quality of information available to support management’s assumptions.

The most significant assumptions relate to the estimated fair values assigned to 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 oil 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 a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected. See Note 4—Acquisitions and Divestitures of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the estimated fair value of assets acquired and liabilities assumed in the QEP Merger and Guidon Acquisition, including any significant changes in these estimates from the date of acquisition.

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 the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial 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

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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.

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. As of December 31, 2021, we had established a total valuation allowance of $315 million, including a valuation allowance for the full amount of Viper’s deferred tax assets. The valuation allowance remains in place based on the uncertainty of future events, including Viper’s ability to generate future taxable income in excess of special allocations to be made to Diamondback, and management considered this and other factors in evaluating the realizability of Viper’s deferred tax assets. No such valuation allowance was determined to be necessary against Rattler’s deferred tax assets as of December 31, 2021 based on the relative predictability of its future income stream based on its long term customer contracts. Any changes in the positive or negative evidence evaluated when determining if Viper’s or Rattler’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 record 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 IRC Section 382 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, 2021, although the Company’s recent cumulative losses represent negative evidence regarding reliance on future taxable income exclusive of reversing temporary differences, 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, 2021, our uncertain tax positions were insignificant, 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

See Note 2—Summary of Significant Accounting Policies included in notes to the consolidated financial statements included elsewhere in this Annual Report for recent accounting pronouncements and accounting policies not yet adopted, if any.

Off-Balance Sheet Arrangements

Please read Note 18—Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Form 10-K for a discussion of our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.