Diamondback Energy, Inc. (FANG) FY 2022 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 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.