AI interpretation based on checked source excerpts. Issuer assertions and evidence limitations remain explicit.
Policy quality-scores-2: six equally weighted categories. The overall score requires full coverage. Missing inputs are not zero. Qualitative grades are sourced interpretations, not probabilities. 2/6 · 19/10/2026
Moat25
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
structural advantage · 1/4 · Concentrated acreage and demonstrated unit cash cost improvements are operating strengths. Market-driven pricing and realized takeaway constraints leave a fragile position without evidenced relative cost superiority; margins alone do not establish a moat.
durability · 1/4 · Reserves deplete without successful replacement, and cash cost performance is uneven across 2023–2025. Existing scale does not establish durable superior economics.
customer dependency · 1/4 · Worldwide and spot-market pricing provide indirect evidence of weak supplier-specific customer dependency. No disclosed switching friction strengthens that position; customer-level behavior remains unavailable.
erosion resilience · 1/4 · Actual negative gas realizations show vulnerability to regional constraints despite operating growth and cost improvements. Additional takeaway capacity could help, but its expected benefit is not yet demonstrated.
Pricing power—
Insufficient evidence for every rubric criterion; no category score is inferred.
realized pricing · 1/4 · Oil realizations rose to $85.26 per barrel in first-half 2026 from $66.99 a year earlier, while gas realizations fell to negative $1.03 per Mcf. These mixed observed outcomes, alongside explicit market price dependence, demonstrate fragile pricing power rather than an inability to assess pricing.
retention · — · Production and sales volumes establish continued market activity, but cannot identify repeat demand from the same customers, renewals or switching friction. Customer retention cannot be established.
margin resilience · 2/4 · Cash operating costs declined in 2025 and operations remained profitable in first-half 2026 despite negative gas revenue and impairment. However, higher depletion charges, the $1.4 billion first-half impairment and commodity price exposure show mixed resilience rather than protected margins.
contractual freedom · 1/4 · Crude oil, condensate and natural gas liquids are sold at negotiated, currently unregulated prices, providing formal negotiating freedom. Economic discretion remains weak because realized pricing is primarily determined by commodity markets and constrained market access.
Predictability—
Missing exact annual revenue, free cash flow or FCF margin; operating cash flow and capex must both be reported for all five years.
Financial strength—
Missing required inputs: debtFcfGrade. Equal-weight grades: debt/FCF (1–8x), net debt/earnings before interest and tax (0–5x), interest service (1–12x), current ratio (0.75–2x). Earnings use reported operating income, or reported pretax profit plus reported interest expense when operating income is unavailable. Interest service uses earnings/interest expense; if unavailable, it uses reported operating cash flow/cash interest paid, without relabeling cash paid as accrued expense. Nonpositive cash flow/earnings score 0 for their service component; reported zero interest with a positive numerator scores 100. Net cash scores 100 for net leverage. Missing disclosures remain unavailable. General nonfinancial-company rubric, not a credit rating; exceptional and nonoperating gains are not normalized out. IFRS finance-cost and cash-flow classifications retain their reported scope.
- netDebtEbitGrade
- 0.00
- interestCoverageGrade
- 38.08
- currentRatioGrade
- 0.00
- Net debt / operating income (x)
- 11.36
- Interest coverage (x)
- 5.19
- Current ratio (x)
- 0.42
Capital allocation—
Missing required inputs: sbcRevenue, cashConversionGrade. Three-year equal-weight indicators: pretax return on average invested capital (0–25%; equity + debt − cash, each year and its prior year), share-count growth (0–5%, lower better), share-based cost/revenue (2–20%, lower better), consolidated FCF/net income (0–1x). Return uses reported operating income or, if unavailable, EBIT calculated from reported pretax profit plus reported interest expense; exceptional/nonoperating gains are not normalized out. Share-based cost uses the reported cash-flow add-back or, if absent, separately reported recognized compensation expense; the latter never becomes an FCF adjustment. Nonpositive net income scores 0 for cash conversion; absent income/FCF stays unavailable. Nonpositive invested capital has no defined return and remains unavailable. Does not establish acquisition quality or buyback timing.
- 3-year pre-tax operating return (%)
- 11.34
- 3-year average dilution (%)
- 18.66
Management56
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
capital discipline · 2/4 · Reported 2025 operating cash flow of $8.8 billion, $3.2 billion returned to shareholders, completed term-loan repayment and bond purchases below par demonstrate actual financial discipline. Acquisition cash spending and share issuance, substantial commitments, impairments and declining ROACE make the overall record mixed; repurchases alone do not prove value creation.
incentive alignment · 2/4 · Actual three-year relative-TSR awards, stock ownership requirements, capital-return metrics and clawback policies support alignment. The August 2026 retirement policy permits accelerated time-based vesting and continued performance-unit eligibility, tempering the assessment. Individual ownership compliance and final performance-award outcomes are not established.
execution · 2/4 · Actual well completions, higher production, lower 2025 unit cash operating expense and completed debt transactions support execution. This is assessed from operating outcomes, not customer retention. Impairments, declining capital returns and unresolved gas takeaway constraints temper the record, and acquisition-related growth is not assumed organic.
governance · 3/4 · Implemented proxy access, majority voting, removal of supermajority requirements, special-meeting rights, clawback provisions and at least 90% director attendance provide strong demonstrated procedural evidence. These do not prove exceptional governance effectiveness; material SGF repurchases and incomplete related-party review disclosures remain limitations.
Evidence
7 Table of Contents Oil and Natural Gas 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 the fields containing 15% or more, along with other production from fields containing less than 15%, of our total proved reserves: Midland Basin Delaware Basin Other Total Production Data: Year Ended December 31, 2025 Oil (MBbls) 167,183 13,839 440 181,462 Natural gas (MMcf) 405,840 38,748 3,267 447,855 Natural gas liquids (MBbls) 74,512 5,395 166 80,073 Total (MBOE) 309,335 25,692 1,151 336,178 Year Ended December 31, 2024 Oil (MBbls) 104,875 18,325 125 123,325 Natural gas (MMcf) 222,574 52,349 757 275,680 Natural gas liquids (MBbls) 41,559 8,084 57 49,700 Total (MBOE) 183,530 35,134 308 218,972 Year Ended December 31, 2023 Oil (MBbls) 75,859 20,246 71 96,176 Natural gas (MMcf) 140,721 57,129 267 198,117 Natural gas liquids (MBbls) 25,899 8,296 22 34,217 Total (MBOE) 125,212 38,064 138 163,413 The following table sets forth certain price and cost information for each of the periods indicated: Year Ended December 31, 2025 2024 2023 Average Prices: Oil ($ per Bbl) $ 64.04 $ 73.52 $ 75.68 Natural gas ($ per Mcf) $ 0.89 $ 0.32 $ 1.32 Natural gas liquids ($ per Bbl) $ 17.88 $ 18.99 $ 20.08 Combined ($ per BOE) $ 40.02 $ 46.12 $ 50.35 Oil, hedged ($ per Bbl)(1) $ 63.14 $ 72.68 $ 74.72 Natural gas, hedged ($ per Mcf)(1) $ 1.84 $ 0.91 $ 1.48 Natural gas liquids, hedged ($ per Bbl)(1) $ 17.88 $ 18.99 $ 20.08 Average price, hedged ($ per BOE)(1) $ 40.79 $ 46.38 $ 49.98 Average Costs ($/BOE): Lease operating expenses $ 5.55 $ 5.87 $ 5.34 Production and ad valorem taxes 2.53 2.91 3.21 Gathering, processing and transportation expense 1.53 1.63 1.76 General and administrative - cash component 0.62 0.68 0.59 Total operating expense - cash $ 10.23 $ 11.09 $ 10.90 General and administrative - non-cash component $ 0.24 $ 0.30 $ 0.33 Depreciation, depletion, amortization and accretion $ 14.99 $ 13.02 $ 10.68 Interest expense, net $ 0.73 $ 0.62 $ 0.97 Production Costs(2) $ 7.08 $ 7.50 $ 7.10 (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.
Oil and Natural Gas Production and Price History; 2023–2025 production, prices and unit costs · Filed 25/02/2026
As of June 30, 2026, we had approximately 902,005 net acres in the Permian Basin, which included approximately 808,401 net acres in the Midland Basin and 93,604 net acres in the Delaware Basin.
MD&A; Upstream Operations; acreage as of June 30, 2026 · Filed 05/08/2026
Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both.
Risk factors; depletion and reserve replacement · Filed 26/02/2025
The unfavorable differentials were primarily driven by regional natural gas takeaway constraints in the Permian Basin, which resulted in periods of negative pricing at Waha Hub.
MD&A; realized regional takeaway constraints and negative Waha pricing · Filed 05/08/2026
32 Table of Contents Comparison of the Six Months Ended June 30, 2026, and 2025 The following table sets forth selected operating data for the periods indicated: Six Months Ended June 30, 2026 2025 Revenues (In millions): Oil sales $ 8,072 $ 5,891 Natural gas sales (255) 309 Natural gas liquid sales 794 773 Total oil, natural gas and natural gas liquid revenues $ 8,611 $ 6,973 Production Data: Oil (MBbls) 94,680 87,943 Natural gas (MMcf) 246,681 210,697 Natural gas liquids (MBbls) 44,955 37,209 Combined volumes (MBOE)(1) 180,749 160,268 Daily oil volumes (BO/d) 523,094 485,873 Daily combined volumes (BOE/d) 998,613 885,459 Average Prices: Oil ($ per Bbl) $ 85.26 $ 66.99 Natural gas ($ per Mcf) $ (1.03) $ 1.47 Natural gas liquids ($ per Bbl) $ 17.66 $ 20.77 Combined ($ per BOE) $ 47.64 $ 43.51 Oil, hedged ($ per Bbl)(2) $ 83.53 $ 66.10 Natural gas, hedged ($ per Mcf)(2) $ 0.73 $ 2.35 Natural gas liquids, hedged ($ per Bbl)(2) $ 17.66 $ 20.77 Average price, hedged ($ per BOE)(2) $ 49.15 $ 44.19 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
MD&A; six months ended June 30, 2026 versus 2025; production and realized prices · Filed 05/08/2026
The Company expects the impact of these constraints to be reduced later in 2026 as its secured takeaway capacity is meaningfully increased through the execution of new contracts and expanded infrastructure build out in the region.
MD&A; management expectation for additional takeaway capacity later in 2026 · Filed 05/08/2026
Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production.
Commodity Price Risk; worldwide crude oil and spot natural gas price determinants · Filed 25/02/2026
Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices.
Regulation; Oil Sales and Transportation; negotiated sales prices · Filed 25/02/2026
and Subsidiaries Condensed Consolidated Statements of Operations (Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (In millions, except per share amounts, shares in thousands) Revenues: Oil sales $ 4,627 $ 2,852 $ 8,072 $ 5,891 Natural gas sales (276) 97 (255) 309 Natural gas liquid sales 435 367 794 773 Sales of purchased oil 739 335 1,124 709 Other operating income 37 27 67 44 Total revenues 5,562 3,678 9,802 7,726 Costs and expenses: Lease operating expenses 552 440 1,099 848 Production and ad valorem taxes 302 214 570 442 Gathering, processing and transportation 113 145 233 256 Purchased oil expense 730 331 1,123 713 Depreciation, depletion, amortization and accretion 1,272 1,266 2,565 2,363 Impairment of oil and natural gas properties — — 1,400 — General and administrative expenses 72 67 151 140 Other operating expenses, net 9 76 33 152 Total costs and expenses 3,050 2,539 7,174 4,914 Income (loss) from operations 2,512 1,139 2,628 2,812 Other income (expense): Interest expense, net (56) (56) (119) (96) Other income (expense), net (4) 2 3 37 Gain (loss) on derivative instruments, net 49 (197) 166 29 Gain (loss) on extinguishment of debt, net 134 55 133 55 Total other income (expense), net 123 (196) 183 25 Income (loss) before income taxes 2,635 943 2,811 2,837 Provision for (benefit from) income taxes 580 204 612 607 Net income (loss) 2,055 739 2,199 2,230 Net income (loss) attributable to non-controlling interest 173 40 292 126 Net income (loss) attributable to Diamondback Energy, Inc.
Condensed Consolidated Statements of Operations; first-half 2026 results and impairment · Filed 05/08/2026
$ 1,664 $ 3,338 $ 3,143 $ 4,386 $ 2,182 Net income (loss) attributable to non-controlling interest (117 ) 363 193 176 94 Net income (loss) 1,547 3,701 3,336 4,562 2,276 Non-cash (gain) loss on derivative instruments, net (160 ) (188 ) 149 (264 ) (377 ) Interest expense, net 244 135 159 154 199 Depreciation, depletion, amortization and accretion 5,038 2,850 1,746 1,344 1,275 Depreciation and interest expense related to equity method investments 84 91 70 63 43 (Gain) loss on extinguishment of debt (56 ) (2 ) 4 99 75 Impairment of oil and natural gas properties 3,652 — — — — Non-cash equity-based compensation expense 114 95 80 76 71 Capitalized equity-based compensation expense (33 ) (30 ) (26 ) (21 ) (20 ) Other non-cash transactions (476 ) 241 (41 ) 25 65 Provision for (benefit from) income taxes 327 800 912 1,174 631 Consolidated Adjusted EBITDA $ 10,281 $ 7,693 $ 6,389 $ 7,212 $ 4,238 Consolidated Adjusted EBITDA $ 10,281 $ 7,693 $ 6,389 $ 7,212 $ 4,238 Depreciation, depletion, amortization and accretion (5,038 ) (2,850 ) (1,746 ) (1,344 ) (1,275 ) Adjusted EBIT $ 5,243 $ 4,843 $ 4,643 $ 5,868 $ 2,963 Adjustment for effect of Endeavor Merger — (608 ) — — — Further Adjusted EBIT $ 5,243 $ 4,235 $ 4,643 $ 5,868 $ 2,963 Total Assets $ 71,059 $ 67,292 $ 29,001 $ 26,209 $ 22,898 Current Liabilities $ (4,600 ) $ (4,811 ) $ (2,108 ) $ (1,716 ) $ (1,438 ) Capital Employed $ 66,459 $ 62,481 $ 26,893 $ 24,493 $ 21,460 Average Capital Employed $ 64,470 $ 44,687 $ 25,693 $ 22,977 $ 18,922 Adjustment for effect of Endeavor Merger — (17,240 ) — — — Further Adjusted Average Capital Employed $ 64,470 $ 27,447 $ 25,693 $ 22,977 $ 18,922 ROACE 8.1 % 10.8 % 18.1 % 25.5 % 15.7 % Adjusted ROACE 8.1 % 15.4 % 18.1 % 25.5 % 15.7 % DIAMONDBACK ENERGY, INC.
Schedule A; 2021–2025 earnings, impairments and ROACE reconciliation · Filed 09/04/2026
DIAMONDBACK ENERGY, INC. • 2026 PROXY STATEMENT 9 Back to Contents 2025 and Q1 2026 Performance Highlights Financial and Operational Highlights • Maintained investment grade credit ratings from all three major ratings agencies • Generated $8.8 billion in net cash provided by operating activities and $5.5 billion Free Cash Flow(1) • Returned a total of $4.05 per share in dividends • Repurchased over 13.84 million shares of Diamondback’s common stock for approximately $2.0 billion • Returned $3.2 billion, or approximately 54% of Adjusted Free Cash Flow(1), to stockholders through our base dividend and stock buyback program • Increased our annual base dividend for the fourth quarter of 2025 to $4.20 per share, representing a 5% increase over year end 2024 Strategic Transactions • Completed the previously announced 2025 Drop Down, consisting of a divestment by our wholly owned subsidiary Endeavor Energy Resources, LP of all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC to Viper Energy, Inc.
Proxy summary; reported cash generation, dividends and repurchases · Filed 09/04/2026
On April 22, 2026, the Company paid in full the remaining $550 million outstanding principal and terminated the 2025 Term Loan.
Note 8; actual repayment and termination of the 2025 Term Loan · Filed 05/08/2026
In April 2026, the Company completed a tender offer to repurchase an aggregate principal amount of $777 million of its senior notes, which consisted of $283 million of the 4.400% Senior Notes due 2051 and $494 million of the 4.250% Senior Notes due 2052 for total cash consideration, including accrued interest, of approximately $632 million, at an average of 81.1% of par value.
Note 8; April 2026 senior note tender completed below par · Filed 05/08/2026
Closed the acquisition of certain subsidiaries of Double Eagle IV Midco, LLC in exchange for approximately 6.84 million shares of Company common stock and $3.1 billion of cash, which added approximately 40,000 net acres in the core of the Midland Basin and 407 estimated gross horizontal locations to the Company’s portfolio
Performance highlights; completed Double Eagle acquisition consideration and acquired assets · Filed 09/04/2026
At December 31, 2025, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $3.0 billion, (ii) electrical power purchase commitments totaling $495 million, (iii) asset retirement obligations totaling $542 million, (iv) electric fracturing fleet and related power generation services commitments totaling $124 million, (v) compressor rental commitments totaling $90 million, and (vi) minimum purchase commitments for quantities of sand used in our drilling operations totaling $56 million.
Liquidity and capital resources; actual contractual commitments at December 31, 2025 · Filed 25/02/2026
In March 2025, eligible employees received performance restricted stock unit awards totaling 171,638 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of TSR of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2025 to December 31, 2027, and cliff vest at December 31, 2027, subject to continued employment.
Note 10; granted March 2025 performance units and three-year TSR conditions · Filed 25/02/2026
We require substantial stock ownership for our non-employee directors and executive officers and they must maintain their applicable stock ownership levels for as long as they serve on our board or are executive officers.
Executive compensation practices; stock ownership and maintenance requirements · Filed 09/04/2026
• 2026 PROXY STATEMENT 30 Back to Contents • Our board of directors and the nominating and corporate governance committee approved enhancements to the nominating committee charter and director nomination process that focused on increasing the size of the board and number of independent directors, with a supermajority of the board currently being independent; • Our board of directors created the safety, sustainability and corporate responsibility committee focused on sound strategy and best policies and practices regarding environmental, safety, human capital and social responsibility matters; • Our board of directors adopted and annually evaluates Corporate Governance Guidelines as an additional step to reinforce our commitment to prudent corporate governance practices and policies; • The compensation committee eliminated single-trigger change of control provisions in all Company equity awards granted since the beginning of 2018; • The compensation committee enhanced the disclosure of targets and goals for performance-based awards, the discussion of equity award process for our named executive officers and the underlying rationale for such awards; • The compensation committee added return on average capital employed and environmental and safety goals among metrics for determining cash performance awards beginning in 2020 and maintained the weighting attributable to the environmental and safety component of our annual incentive metrics at 25% for 2025; • Our board of directors implemented and maintains rigorous stock ownership and retention guidelines for our executive officers and non-employee directors; • Our board of directors adopted a comprehensive executive incentive compensation clawback policy compliant with Nasdaq listing standards and implementing Rule 10D-1 of the Exchange Act; • Our Lead Independent Director participated in an investor outreach call with one of our large stockholders; • Our board of directors adopted a Human Rights Policy; and • Our safety, sustainability and corporate responsibility committee adopted a Policy Governing Corporate Political Contributions.
Stockholder engagement; implemented governance, compensation and clawback policies · Filed 09/04/2026
Upon a qualifying retirement, a participant will be entitled to: •full accelerated vesting of all outstanding and unvested restricted stock units held by the participant that were granted on or after the effective date of the Executive Retirement Policy; •continued eligibility to vest in all outstanding performance stock units held by the participant, based on actual achievement of applicable performance goals, for up to 12 months following the participant’s retirement date (or 24 months for participants with at least 15 years of employment); •a prorated target annual bonus for the year in which the retirement date occurs; and •a lump-sum cash payment equal to the participant’s monthly COBRA premium multiplied by the lesser of 18 and the number of months (including full and partial months) between the participant’s retirement date and the date on which the participant attains age 65.
Other Information; benefits under the Executive Retirement Policy effective August 1, 2026 · Filed 05/08/2026
In response to feedback obtained during our stockholder outreach efforts, the following past actions, some of which have already been independently considered for implementation by our board of directors or committees, were undertaken: • Our board of directors amended our bylaws to provide our stockholders with proxy access; • Our board of directors also amended our bylaws to provide for the majority vote requirement to elect directors to our board, which replaced the prior plurality voting standard applicable to our director election; • Amended our charter to eliminate the 66 2/3% supermajority vote requirements; • Amended our governing documents to provide stockholders with the right to call a special meeting; DIAMONDBACK ENERGY, INC.
Stockholder engagement; adopted proxy access, majority voting and stockholder rights · Filed 09/04/2026
In 2025, each director attended at least 90% of the meetings of the board of directors and the meetings of the committees on which he or she served.
Board meetings; actual 2025 director attendance · Filed 09/04/2026
During the six months ended June 30, 2026, the Company repurchased approximately $689 million, which included approximately $509 million for the repurchases from SGF, in each case, excluding excise tax.
Note 9; actual first-half 2026 repurchases, including purchases from SGF · Filed 05/08/2026
The following table sets forth the total number of operated horizontal wells drilled and completed during the periods indicated: Three Months Ended June 30, 2026 Six Months Ended June 30, 2026 Drilled Completed(1) Drilled Completed(2) Area: Gross Net Gross Net Gross Net Gross Net Midland Basin 97 89 168 157 215 200 315 294 Total 97 89 168 157 215 200 315 294 (1)The average lateral length for the wells completed during the second quarter of 2026 was 11,983 feet.
MD&A; actual operated wells drilled and completed in first-half 2026 · Filed 05/08/2026
After the removal of Marathon Oil Corporation, Continental Resources, Inc., Hess Corporation and Pioneer Natural Resources Company, and the addition of ConocoPhillips, Occidental Petroleum Corp and Permian Resources Corporation, the 2022 peer group, 2023 peer group, 2024 peer group and 2025 peer group are made up of the same companies.
Compensation disclosures; changes to designated peer groups · Filed 09/04/2026
32 Table of Contents Comparison of the Six Months Ended June 30, 2026, and 2025 The following table sets forth selected operating data for the periods indicated: Six Months Ended June 30, 2026 2025 Revenues (In millions): Oil sales $ 8,072 $ 5,891 Natural gas sales (255) 309 Natural gas liquid sales 794 773 Total oil, natural gas and natural gas liquid revenues $ 8,611 $ 6,973 Production Data: Oil (MBbls) 94,680 87,943 Natural gas (MMcf) 246,681 210,697 Natural gas liquids (MBbls) 44,955 37,209 Combined volumes (MBOE)(1) 180,749 160,268 Daily oil volumes (BO/d) 523,094 485,873 Daily combined volumes (BOE/d) 998,613 885,459 Average Prices: Oil ($ per Bbl) $ 85.26 $ 66.99 Natural gas ($ per Mcf) $ (1.03) $ 1.47 Natural gas liquids ($ per Bbl) $ 17.66 $ 20.77 Combined ($ per BOE) $ 47.64 $ 43.51 Oil, hedged ($ per Bbl)(2) $ 83.53 $ 66.10 Natural gas, hedged ($ per Mcf)(2) $ 0.73 $ 2.35 Natural gas liquids, hedged ($ per Bbl)(2) $ 17.66 $ 20.77 Average price, hedged ($ per BOE)(2) $ 49.15 $ 44.19 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
Page 32, Results of Operations—Comparison of the Six Months Ended June 30, 2026, and 2025 · Filed 05/08/2026
32 Table of Contents Comparison of the Six Months Ended June 30, 2026, and 2025 The following table sets forth selected operating data for the periods indicated: Six Months Ended June 30, 2026 2025 Revenues (In millions): Oil sales $ 8,072 $ 5,891 Natural gas sales (255) 309 Natural gas liquid sales 794 773 Total oil, natural gas and natural gas liquid revenues $ 8,611 $ 6,973 Production Data: Oil (MBbls) 94,680 87,943 Natural gas (MMcf) 246,681 210,697 Natural gas liquids (MBbls) 44,955 37,209 Combined volumes (MBOE)(1) 180,749 160,268 Daily oil volumes (BO/d) 523,094 485,873 Daily combined volumes (BOE/d) 998,613 885,459 Average Prices: Oil ($ per Bbl) $ 85.26 $ 66.99 Natural gas ($ per Mcf) $ (1.03) $ 1.47 Natural gas liquids ($ per Bbl) $ 17.66 $ 20.77 Combined ($ per BOE) $ 47.64 $ 43.51 Oil, hedged ($ per Bbl)(2) $ 83.53 $ 66.10 Natural gas, hedged ($ per Mcf)(2) $ 0.73 $ 2.35 Natural gas liquids, hedged ($ per Bbl)(2) $ 17.66 $ 20.77 Average price, hedged ($ per BOE)(2) $ 49.15 $ 44.19 (1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
Page 32, Results of Operations, six months ended June 30, 2026 and 2025 operating data · Filed 05/08/2026
