AI interpretation based on checked source excerpts. Issuer assertions and evidence limitations remain explicit.
Policy quality-scores-3: six equally weighted categories. The overall score requires full coverage. Missing inputs are not zero. Qualitative grades are sourced interpretations, not probabilities. 3/6 · 31/10/2026
Moat25
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
structural advantage · 1/4 · Large acreage, completed wells and lower 2025 cash operating expense demonstrate operating capability. Market-driven prices and actual gas constraints leave a fragile competitive position; neither scale nor absolute costs establish relative cost superiority.
durability · 1/4 · Reserves deplete without replacement, historical costs are uneven and first-half 2026 lease operating expense rose. Some transportation-expense improvement reflects accounting presentation. Sustained superior full-cycle economics are not established.
customer dependency · 1/4 · Worldwide and spot-market pricing, together with product contracts that do not exist beyond each day's production, support weak supplier-specific dependency. This is a contractual and business-model inference; customer switching behavior is undisclosed.
erosion resilience · 1/4 · Negative gas realizations demonstrate actual exposure to regional infrastructure constraints despite production growth. Additional secured takeaway offers potential mitigation, but its expected improvement is not demonstrated in the supplied results.
Pricing power31
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
realized pricing · 1/4 · First-half oil realizations rose to $85.26 per barrel from $66.99, while gas fell to negative $1.03 per Mcf from positive $1.47. These observed outcomes, market-driven pricing and realized basis constraints indicate weak pricing power rather than an unassessable criterion.
retention · 1/4 · Continuing and growing commodity sales provide indirect evidence of ongoing aggregate demand. Daily production-based contracts and market pricing provide little demonstrated protection of repeat demand for Diamondback specifically. No customer retention rate or realized customer loss is inferred.
margin resilience · 2/4 · Lower 2025 cash costs and positive first-half 2026 operating income demonstrate some resilience. Higher lease operating costs, a $1.4 billion first-half impairment and negative gas realizations temper that evidence. Profitability does not itself establish a moat.
contractual freedom · 1/4 · Unregulated, negotiated oil and liquids prices provide formal negotiating freedom, and product obligations are short-lived. Economic discretion is weak because realizations primarily follow commodity markets and constrained transportation access.
Predictability—
Missing exact annual revenue, free cash flow or FCF margin; operating cash flow and capex must both be reported for every observed year.
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, an original issuer-reported unadjusted EBIT reconciled to net income, income tax and signed net interest, or reported pretax profit plus reported gross interest expense. Reported EBIT is distinct from GAAP operating income and gross interest. 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, an original issuer-reported unadjusted EBIT reconciled to net income, income tax and signed net interest, or EBIT calculated from reported pretax profit plus reported gross interest expense; the issuer-reported EBIT is distinct from GAAP operating income and gross interest; 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. ROIC remains undefined for nonpositive invested capital; the explicit asset-return alternative does not change the ROIC chart. Missing financial inputs alone never trigger an alternative. 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 · First-half operating cash flow of $5.417 billion, $1.929 billion of property additions, completed term-loan repayment and notes purchased below par demonstrate actual financial discipline. Acquisition cash spending and dilution, substantial commitments, impairments and declining disclosed capital returns make the overall record mixed. Removal of the minimum distribution commitment increases discretion; buybacks do not alone prove value creation.
incentive alignment · 2/4 · Granted three-year relative-TSR awards, an absolute-TSR modifier, ownership requirements, capital-return metrics and an adopted clawback policy support alignment. The subsequently adopted retirement policy allows accelerated time-based vesting and continued performance-award eligibility. Individual ownership compliance and final performance payouts are not established.
execution · 2/4 · Completed wells, higher production, lower 2025 cash operating costs and completed debt transactions demonstrate execution through operating outcomes. Acquisition contributions to growth, rising 2026 lease operating costs, impairments and gas constraints temper the record. Management's claim of operating superiority is an assertion rather than comparative proof.
governance · 3/4 · Implemented stockholder rights, clawback provisions, at least 90% director attendance, completed transition to a non-executive chairman and the annual say-on-pay determination provide strong procedural evidence. SGF repurchases had audit-committee approval. September amendments and actual board departures update the structure, but do not prove eliminated influence or exceptional governance effectiveness.
Evidence
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.
2026 second-quarter Form 10-Q, Upstream Operations, acreage · Filed 05/08/2026
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.
2025 Form 10-K, Oil and Natural Gas Production and Price History, page 7 · Filed 25/02/2026
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.
2026 second-quarter Form 10-Q, operated wells drilled and completed · Filed 05/08/2026
Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:
Six Months Ended June 30,
2026
2025
(In millions, except per BOE amounts)
Amount
Per BOE
Amount
Per BOE
Lease operating expenses
$
1,099
$
6.08
$
848
$
5.29
Lease operating expenses increased for the six months ended June 30, 2026, compared to the same period in 2025, primarily due to (i) a $54 million increase in water disposal costs following the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary in the fourth quarter of 2025, (ii) recording a $43 million reduction in estimated prior period water related costs during the six months ended June 30, 2025, (iii) a $36 million increase to operate wells acquired in the Double Eagle Acquisition, (iv) a $35 million increase in workover and maintenance costs and (v) a $34 million increase attributable to higher production volumes during the six months ended June 30, 2026, (vi) a downward adjustment to initial cost estimates related to producing properties acquired in connection with the Endeavor Acquisition during the six months ended June 30, 2025, and (vii) other individually insignificant activity.
2026 second-quarter Form 10-Q, Lease Operating Expenses · Filed 05/08/2026
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.
2026 second-quarter Form 10-Q, commodity prices and gas takeaway constraints · 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.
2026 second-quarter Form 10-Q, first-half operating data, page 32 · 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.
2024 Form 10-K, risk passage on reserve depletion · Filed 26/02/2025
Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production.
2025 Form 10-K, Commodity Price Risk · 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.
2025 Form 10-K, Oil Sales and Transportation · Filed 25/02/2026
The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each day’s production.
2025 Form 10-K, Transaction Price Allocated to Remaining Performance Obligations · 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.
2026 second-quarter Form 10-Q, Condensed Consolidated Statements of Operations · Filed 05/08/2026
Changes in operating assets and liabilities:
Accounts receivable
(563)
160
Accounts payable and accrued liabilities
(204)
(383)
Income taxes payable
—
(309)
Revenues and royalties payable
324
(30)
Other
(104)
1
Net cash provided by (used in) operating activities
5,417
4,032
Cash flows from investing activities:
2026 second-quarter Form 10-Q, operating cash flows · Filed 05/08/2026
Additions to oil and natural gas properties
(1,929)
(1,806)
Property acquisitions
(752)
(3,875)
Proceeds from sale of assets
657
57
Other
(29)
(8)
Net cash provided by (used in) investing activities
(2,053)
(5,632)
Cash flows from financing activities:
Proceeds from debt
6,290
8,622
Repayment of debt
(8,047)
(6,407)
Repurchased shares under repurchase program
(180)
(973)
Repurchased shares - related party
(509)
—
Repurchased shares/units under Viper’s repurchase program
(228)
(10)
Net proceeds from Viper’s issuance of common stock
—
1,232
Proceeds from sale of Viper's common stock
589
—
Dividends paid to stockholders
(605)
(581)
Dividends to non-controlling interest
(279)
(177)
Other
(37)
(49)
Net cash provided by (used in) financing activities
(3,006)
1,657
Net increase (decrease) in cash, cash equivalents and restricted cash
358
57
Cash, cash equivalents and restricted cash at beginning of period
106
164
Cash, cash equivalents and restricted cash at end of period
$
464
$
221
See accompanying notes to condensed consolidated financial statements.
2026 second-quarter Form 10-Q, investing and financing cash flows · Filed 05/08/2026
On April 22, 2026, the Company paid in full the remaining $550 million outstanding principal and terminated the 2025 Term Loan.
2026 second-quarter Form 10-Q, repayment and termination of 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.
2026 second-quarter Form 10-Q, senior-note tender offer · 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.
2026 proxy statement, ROACE reconciliation · Filed 09/04/2026
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
2026 proxy statement, completed Double Eagle acquisition · Filed 09/04/2026
For each NEO, these amounts represent the performance-based restricted stock units granted under the Equity Incentive Plan, which awards are subject to the satisfaction of certain relative TSR performance conditions compared to the Company’s TSR performance peer group for the three-year performance period commencing on January 1, 2025 and ending on December 31, 2027, as certified by the compensation committee, and continuous service requirements.
2026 proxy statement, granted Diamondback performance-based equity awards · Filed 09/04/2026
The absolute TSR modifier reduces payouts upon negative performance period TSR, pays at target upon achieving a performance period annual TSR of zero to 15%, and increases payouts upon achieving a performance period annual TSR of greater than 15%.
2026 proxy statement, absolute TSR payout modifier · 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.
2026 proxy statement, implemented governance and compensation policies, page 30 · 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.
2026 second-quarter Form 10-Q, Executive Retirement Policy benefits · 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.
2026 proxy statement, implemented stockholder-rights amendments · 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.
2026 proxy statement, 2025 director meeting attendance · Filed 09/04/2026
Repurchases under the letter agreement are pursuant to the Company’s existing share repurchase program, and have been approved by the audit committee of the Company’s board of directors.
2026 second-quarter Form 10-Q, audit-committee approval of SGF repurchases · Filed 05/08/2026
During the six months ended June 30, 2026, the Company repurchased 3.0 million shares from SGF for approximately $509 million, excluding excise taxes.
2026 second-quarter Form 10-Q, first-half SGF repurchases · Filed 05/08/2026
Approximately 33% of the increase in our combined production volumes was attributable to Viper’s Sitio Acquisition and 16% was attributable to the Double Eagle Acquisition.
2026 second-quarter Form 10-Q, acquisition contributions to production growth · 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.
2026 second-quarter Form 10-Q, expected additional gas takeaway capacity · Filed 05/08/2026
The decrease in the overall rate per BOE between 2024 and 2023 is due to recording gathering, processing and transportation charges for production from the Endeavor Acquisition as a reduction to revenue in accordance with the terms of the acquired contracts.
2024 Form 10-K, accounting explanation for lower transportation expense per BOE · Filed 26/02/2025
Return of Capital Commitment
Beginning in the second quarter of 2026, our board of directors approved the removal of our minimum 50% return of capital quarterly commitment to allow the Company more discretion in the allocation of Free Cash Flow.
2026 second-quarter Form 10-Q, removal of minimum return-of-capital commitment · Filed 05/08/2026
Stice stepped down as Executive Chairman of the Board of Directors of the Company (the “Board”) and became non-executive Chairman of the Board, in each case effective as of May 20, 2026, the date of the Company’s 2026 Annual Meeting of Stockholders (the “2026 Annual Meeting”).
May 20, 2026 Form 8-K, completed transition to non-executive chairman · Filed 20/05/2026
The results of the stockholder vote on Proposal 3 were as follows:
1 Year
2 Years
3 Years
Abstain
Non-Votes
246,338,007
371,078
2,888,098
177,944
14,899,987
In light of these results, the Board determined that the Company will hold an advisory vote on the compensation paid to the Company’s named executive officers every year.
May 20, 2026 Form 8-K, advisory-vote results and annual say-on-pay determination · Filed 20/05/2026
own at least 10% but less than 25% of the Outstanding Shares (as defined in the Stockholders Agreement), and (y) no directors to
September 30, 2026 Form 8-K, amended stockholder director-designation thresholds · Filed 30/09/2026
the Board if the Stephens Stockholders beneficially own less than 10% of the Outstanding Shares.
September 30, 2026 Form 8-K, termination of designation rights below ownership threshold · Filed 30/09/2026
operations, policies or practices, Darin Holderness and Lance Robertson resigned from the Board on September 29, 2026 and September 30, 2026, respectively.
September 30, 2026 Form 8-K, completed board resignations · Filed 30/09/2026
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.
2026 proxy statement, compensation peer-group changes · Filed 09/04/2026
Our operations team demonstrated why they are the best in the business, putting us in an advantaged position to bring forward material value on our differentiated asset base.
August 3, 2026 shareholder letter, management assertion of operating superiority · Filed 03/08/2026
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.
2025 Form 10-K, significant contractual obligations · Filed 25/02/2026
This net increase consisted of an additional $973 million from higher average prices received for our oil production, offset partially by lower natural gas and natural gas liquids prices received in 2026 and an additional $665 million from the 13% growth in our combined production volumes.
2026 second-quarter Form 10-Q, price and production contributions to revenue growth · Filed 05/08/2026
