What changed in Diamondback Energy's 10-K — 2022 vs 2023

Item 1A. Risk Factors ” for a discussion of risks and uncertainties associated with our estimates of proved reserves and related factors, and see Note 18— Supplemental Information on Oil and Natural Gas Operations of the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of our reserve estimates and pricing.

Proved Undeveloped Reserves (PUDs) As of December 31, 2022, our proved undeveloped reserves totaled 369,995 MBbls of oil, 746,079 MMcf of natural gas and 135,076 MBbls of natural gas liquids, for a total of 629,418 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table includes the changes in PUD reserves for 2022 (MBOE): Beginning proved undeveloped reserves at December 31, 2021 587,889 Undeveloped reserves transferred to developed (155,457) Revisions (82,619) Purchases 8,734 Divestitures (93) Extensions and discoveries 270,964 Ending proved undeveloped reserves at December 31, 2022 629,418 The increase in proved undeveloped reserves was primarily attributable to extensions of 256,007 MBOE from 311 gross (287 net) wells in which we have a working interest and 14,957 MBOE from 199 gross wells in which Viper owns royalty interests.

Of the 311 gross working interest wells, 261 were in the Midland Basin and 50 were in the Delaware Basin.

Transfers of 155,457 MBOE from undeveloped to developed reserves were the result of drilling or participating in 168 gross (155 net) horizontal wells in which we have a working interest and 115 gross wells in which we also have a royalty interest or mineral interest through Viper.

Downward revisions of 82,619 MBOE were primarily the result of negative revisions of 94,880 MBOE due to downgrades related to changes in the corporate development plan, and positive revisions of 12,261 9 Table of Contents MBOE attributable to higher commodity prices.

Purchases of 8,734 MBOE consisted of 8,367 MBOE primarily from the FireBird Acquisition, and 367 MBOE of Viper’s royalty interest purchases. Costs incurred relating to the development of PUDs were approximately $566 million during 2022.

Estimated future development costs relating to the development of PUDs are projected to be approximately $1.4 billion in 2023, $1.4 billion in 2024, $882 million in 2025 and $659 million in 2026.

Since our formation in 2011, our average drilling costs and drilling times have been reduced, and we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately $50.00 per Bbl WTI, we currently have approximately 8,276 gross (6,055 net) identified economic potential horizontal drilling locations on our acreage based on our evaluation of applicable geologic and engineering data.

With our current development plan, we expect to continue our strong PUD conversion ratio in 2023 by converting an estimated 33% of our PUDs to a proved developed category and developing approximately 80% of the consolidated 2022 year-end PUD reserves by the end of 2025.

As of December 31, 2022, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

The following table presents the number of gross identified economic potential horizontal drilling locations by basin: Number of Identified Economic Potential Horizontal Drilling Locations Midland Basin Lower Spraberry (1) 1,100 Middle Spraberry (1) 924 Wolfcamp A (2) 665 Wolfcamp B (2) 793 Other 1,772 Total Midland Basin 5,254 Delaware Basin 2nd Bone Springs (3) 652 3rd Bone Springs (3) 963 Wolfcamp A (3) 359 Wolfcamp B (3) 585 Other 463 Total Delaware Basin 3,022 Total 8,276 (1) Our current location count is based on 660 foot to 880 foot spacing in Midland, Martin and northeast Andrews counties, depending on the prospect area and 880 foot spacing in all other counties.

(2) Our current location count is based on 660 foot to 880 foot spacing in Midland and Howard counties, depending on the prospect area and 880 foot spacing in all other counties.

(3) Our current location count is based on 880 foot to 1,320 foot spacing. 10 Table of Contents Oil and Natural Gas Production Prices and Production Costs Production and Price History The following tables set forth information regarding our net production of oil, natural gas and natural gas liquids by basin for each of the periods indicated: Midland Basin Delaware Basin Other (1) Total Production Data: Year Ended December 31, 2022 Oil (MBbls) 58,803 22,681 132 81,616 Natural gas (MMcf) 116,579 59,338 459 176,376 Natural gas liquids (MBbls) 20,800 9,016 64 29,880 Total (MBOE) 99,033 41,587 273 140,892 Year Ended December 31, 2021 Oil (MBbls) 52,112 25,672 3,738 81,522 Natural gas (MMcf) 96,083 66,034 7,289 169,406 Natural gas liquids (MBbls) 17,010 8,749 1,487 27,246 Total (MBOE) 85,136 45,427 6,440 137,002 Year Ended December 31, 2020 Oil (MBbls) 38,313 27,703 166 66,182 Natural gas (MMcf) 68,529 61,606 414 130,549 Natural gas liquids (MBbls) 12,597 9,295 89 21,981 Total (MBOE) 62,332 47,266 324 109,921 (1) Production data includes (i) Rockies, (ii) High Plains beginning January 1, 2021, (iii) Eagle Ford Shale through October 1, 2022, the effective date on which the properties were divested and (iv) Central Basin Platform through December 31, 2020. 11 Table of Contents The following table sets forth certain price and cost information for each of the periods indicated: Year Ended December 31, 2022 2021 2020 Average Prices: Oil ($ per Bbl) $ 93.85 $ 66.19 $ 36.41 Natural gas ($ per Mcf) $ 4.86 $ 3.36 $ 0.82 Natural gas liquids ($ per Bbl) $ 35.07 $ 28.70 $ 10.87 Combined ($ per BOE) $ 67.90 $ 49.25 $ 25.07 Oil, hedged ($ per Bbl) (1) $ 86.76 $ 52.56 $ 40.34 Natural gas, hedged ($ per Mcf) (1) $ 4.12 $ 2.39 $ 0.67 Natural gas liquids, hedged ($ per Bbl) (1) $ 35.07 $ 28.33 $ 10.83 Average price, hedged ($ per BOE) (1) $ 62.85 $ 39.87 $ 27.26 Average Costs per BOE: Lease operating expenses $ 4.63 $ 4.12 $ 3.87 Production and ad valorem taxes 4.34 3.10 1.77 Gathering and transportation expense 1.83 1.55 1.27 General and administrative - cash component 0.63 0.69 0.46 Total operating expense - cash $ 11.43 $ 9.46 $ 7.37 General and administrative - non-cash component $ 0.39 $ 0.37 $ 0.34 Depletion 8.87 8.77 11.30 Interest expense, net 1.13 1.45 1.79 Merger and integration expense 0.10 0.57 — Total expenses $ 10.49 $ 11.16 $ 13.43 (1) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.

Wells Drilled and Completed in 2022 The following table sets forth the total number of operated horizontal wells drilled and completed during the year ended December 31, 2022: Year Ended December 31, 2022 Drilled Completed Area: Gross Net Gross Net Midland Basin 197 183 213 197 Delaware Basin 43 40 42 39 Other — — — — Total 240 223 255 236 As of December 31, 2022, we operated the following wells: Vertical Wells Horizontal Wells Total Area: Gross Net Gross Net Gross Net Midland Basin 3,028 2,864 2,084 1,936 5,112 4,800 Delaware Basin 39 35 687 643 726 678 Total 3,067 2,899 2,771 2,579 5,838 5,478 12 Table of Contents Productive Wells As of December 31, 2022, we owned an interest in a total of 11,944 gross productive wells with an average unweighted 86% working interest in 6,489 gross (5,574 net) wells and an average 1.9% royalty interest in 5,455 additional wells.

Through our subsidiary Viper, we own an average 3.8% net revenue interest in 8,260 of the total 11,944 gross productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

The following table sets forth information regarding productive wells by basin as of December 31, 2022: Gross Wells Net Wells Oil Natural Gas Total Oil Natural Gas Total Midland Basin 9,170 32 9,202 4,850 11 4,861 Delaware Basin 2,358 272 2,630 683 27 710 Other 57 55 112 3 — 3 Total productive wells 11,585 359 11,944 5,536 38 5,574 Drilling Results The following tables set forth information with respect to the number of wells drilled during the periods indicated by basin.

Each of these wells was drilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

Year Ended December 31, 2022 Midland Basin Delaware Basin Total Gross Net Gross Net Gross Net Development: Productive 59 54 16 15 75 69 Dry — — — — — — Exploratory: Productive 138 129 27 25 165 154 Dry — — — — — — Total: Productive 197 183 43 40 240 223 Dry — — — — — — Year Ended December 31, 2021 Midland Basin Delaware Basin Total Gross Net Gross Net Gross Net Development: Productive 33 30 7 7 40 37 Dry — — — — — — Exploratory: Productive 142 135 34 31 176 166 Dry — — — — — — Total: Productive 175 165 41 38 216 203 Dry — — — — — — 13 Table of Contents Year Ended December 31, 2020 Midland Basin Delaware Basin Total Gross Net Gross Net Gross Net Development: Productive 87 81 26 25 113 106 Dry — — — — — — Exploratory: Productive 46 44 49 45 95 89 Dry — — — — — — Total: Productive 133 125 75 70 208 195 Dry — — — — — — As of December 31, 2022, we had 39 gross (33 net) operated wells in the process of drilling and 22 gross (20 net) wells in the process of completion or waiting on completion.

Acreage The following table sets forth information as of December 31, 2022 relating to our leasehold acreage: Developed Acreage (1) Undeveloped Acreage Total Acreage (2) Basin Gross Net Gross Net Gross Net Midland 221,817 193,626 150,098 131,914 371,915 325,540 Delaware 102,464 78,195 99,160 72,524 201,624 150,719 Exploration 693 693 40,091 30,875 40,784 31,568 Conventional Permian — — 1,025 940 1,025 940 Total 324,974 272,514 290,374 236,253 615,348 508,767 (1) Does not include undrilled acreage held by production under the terms of the lease.

Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.

(2) Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.

Undeveloped Acreage Expirations As of December 31, 2022, the following gross and net undeveloped acres are set to expire over the next 5 years based on their contractual lease maturities unless (i) production is established within the spacing units covering the acreage or (ii) the lease is renewed or extended under continuous drilling provisions prior to the contractual expiration dates.

Acres Expiring Delaware Midland Total Gross Net Gross Net Gross Net 2023 112 93 450 372 562 465 2024 351 290 2,667 2,206 3,018 2,496 2025 150 124 2,980 2,464 3,130 2,588 2026 — — 1,121 927 1,121 927 2027 — — — — — — Total 613 507 7,218 5,969 7,831 6,476 Title to Properties Prior to the drilling of an oil or natural gas well, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well.

To the extent title opinions or other investigations reflect title defects impacting the development or operation of a producing property, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects.

We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards 14 Table of Contents generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, an updated title review, or review previously obtained title opinions.

Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Marketing and Customers We typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2022, two purchasers each accounted for more than 10% of our revenue. For the year ended December 31, 2021, three purchasers each accounted for more than 10% of our revenue.

For the year ended December 31, 2020, four purchasers each accounted for more than 10% of our revenue. We do not require collateral and do not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

For additional information regarding our customer concentrations, see Note 3— Revenue from Contracts with Customers included in the notes to the consolidated financial statements included elsewhere in this Annual Report. Delivery Commitments Certain of our firm sales agreements include delivery commitments that specify the delivery of a fixed and determinable quantity of oil.

We believe our current production and reserves are sufficient to fulfill these delivery commitments and we expect our reserves will continue to be the primary means of fulfilling our future commitments. However, these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment.

For additional information regarding commitments, see Note 15— Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Annual Report. Competition The oil and natural gas industry is intensely competitive, and in our upstream segment, we compete with other companies that may have greater resources.

Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis.

These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

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. 48 Table of Contents 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 Divestiture s 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. 49 Table of Contents 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. 50 Table of Contents 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: Year Ended December 31, 2022 2021 Revenues (in millions): Oil sales $ 7,660 $ 5,396 Natural gas sales 858 569 Natural gas liquid sales 1,048 782 Total oil, natural gas and natural gas liquid revenues $ 9,566 $ 6,747 Production Data: Oil (MBbls) 81,616 81,522 Natural gas (MMcf) 176,376 169,406 Natural gas liquids (MBbls) 29,880 27,246 Combined volumes (MBOE) (1) 140,892 137,002 Daily oil volumes (BO/d) 223,605 223,348 Daily combined volumes (BOE/d) (1) 386,005 375,349 Average Prices: Oil ($ per Bbl) $ 93.85 $ 66.19 Natural gas ($ per Mcf) $ 4.86 $ 3.36 Natural gas liquids ($ per Bbl) $ 35.07 $ 28.70 Combined ($ per BOE) $ 67.90 $ 49.25 Oil, hedged ($ per Bbl) (2) $ 86.76 $ 52.56 Natural gas, hedged ($ per Mcf) (2) $ 4.12 $ 2.39 Natural gas liquids, hedged ($ per Bbl) (2) $ 35.07 $ 28.33 Average price, hedged ($ per BOE) (2) $ 62.85 $ 39.87 (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. 51 Table of Contents 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: Year Ended December 31, 2022 2021 Oil (MBbls) 58 % 60 % Natural gas (MMcf) 21 % 20 % Natural gas liquids (MBbls) 21 % 20 % 100 % 100 % 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: Year Ended December 31, 2022 2021 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Lease operating expenses $ 652 $ 4.63 $ 565 $ 4.12 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: Year Ended December 31, 2022 2021 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Production taxes $ 483 $ 3.43 $ 349 $ 2.55 Ad valorem taxes 128 0.91 76 0.55 Total production and ad valorem expense $ 611 $ 4.34 $ 425 $ 3.10 Production taxes as a % of oil, natural gas, and natural gas liquids revenue 5.0 % 5.2 % 52 Table of Contents 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: Year Ended December 31, 2022 2021 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE Gathering and transportation $ 258 $ 1.83 $ 212 $ 1.55 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: Year Ended December 31, (In millions, except BOE amounts) 2022 2021 Depletion of proved oil and natural gas properties $ 1,250 $ 1,202 Depreciation of other property and equipment 77 48 Other amortization 3 16 Asset retirement obligation accretion 14 9 Depreciation, depletion, amortization and accretion expense $ 1,344 $ 1,275 Oil and natural gas properties depletion rate per BOE $ 8.87 $ 8.77 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. 53 Table of Contents General and Administrative Expenses.

The following table shows general and administrative expenses for the years ended December 31, 2022 and 2021: Year Ended December 31, 2022 2021 (In millions, except per BOE amounts) Amount Per BOE Amount Per BOE General and administrative expenses $ 89 $ 0.63 $ 95 $ 0.69 Non-cash stock-based compensation 55 0.39 51 0.37 Total general and administrative expenses $ 144 $ 1.02 $ 146 $ 1.06 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: Year Ended December 31, 2022 2021 (In millions) Amount Per BOE Amount Per BOE Merger and integration expenses $ 14 $ 0.10 $ 78 $ 0.57 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: Year Ended December 31, (In millions) 2022 2021 Gain (loss) on derivative instruments, net (1) $ (586) $ (848) Net cash received (paid) on settlements (2)(3) $ (850) $ (1,225) (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.

Item 6. [RESERVED] 47 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 48 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 63 Item 8. Financial Statements and Supplementary Data 64 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 64 Item 9A. Controls and Procedures 65

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates —Method of Accounting for Oil and Natural Gas Properties.” If the prices of oil and natural gas decline, we may be required to further write-down the value of our oil and natural gas properties in the future, which could negatively affect our results of operations.

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

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs.

As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production.

Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect.

Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows.

A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history.

Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates.

Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

The reserve estimates represent our net revenue interest in our properties. 33 Table of Contents The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

The standardized measure of our estimated proved reserves are not necessarily the same as the current market value of our estimated proved oil reserves. The present value of future net cash flow from our proved reserves, or standardized measure may not represent the current market value of our estimated proved oil reserves.

In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates.

In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Approximately 31% of our total estimated proved reserves as of December 31, 2022, were proved undeveloped reserves and may not be ultimately developed or produced.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling and completion operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves.

We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated.

Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical.

In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with operating in a single geographic area.

In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. Our producing properties are currently geographically concentrated in the Permian Basin of West Texas.

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

Extreme regional weather events may occur that can affect our suppliers or customers, which could adversely affect us.

For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our production) to be curtailed or shut in or (in the case of natural gas) flared.

Further, any increase in flaring of our natural gas production due to weather-related events or otherwise could make it difficult for us to achieve our publicly-announced sustainability and emissions reduction targets, which could expose us to reputational risks and adversely impact our contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us.

Likewise, a weather event could reduce the availability of electrical power, road accessibility, and transportation facilities, which could have an adverse impact on our production volumes (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.

Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of 34 Table of Contents properties.

Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. In addition to the geographic concentration of our producing properties described above, as of December 31, 2022, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin.

This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field. We depend upon several significant purchasers for the sale of most of our oil and natural gas production.

The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce.

We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “ Item 1 and 2.

Business and Properties —Oil and Natural Gas Production Prices and Production Costs—Marketing and Customers” for additional information regarding these customers. The loss of one or more of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations. The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel.