Diamondback Energy, Inc. (FANG) FY 2023 MD&A

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.