{"schemaVersion":1,"research":true,"symbol":"dvn","name":"Devon Energy","topic":"moat","path":"/stock/dvn/moat","status":"published","version":3,"updatedAt":"2026-10-17T23:47:44.164Z","locked":false,"publicFairValue":false,"fairValue":null,"moat":{"verdict":"none","summary":"The supplied passages establish a competitive commodity producer without a demonstrated durable moat. Scale, productive assets and lower recent unit operating costs provide operating strengths, but comparative cost leadership remains unproven. Realized pricing follows commodity indices and regional constraints, with severe gas discounts demonstrating weak pricing power. The completed Coterra merger expands the asset base; projected synergies and inventory quality claims do not yet establish a defensible advantage.","advantages":[{"mechanism":"cost_advantage","claim":"Potential scale and asset-productivity benefits are partly supported by operating results, but do not establish a durable cost advantage over competitors. Second-quarter 2026 lease operating expense per Boe declined, while gathering, processing and transportation expense per Boe increased; the merger also changed the production mix.","durability":"Unproven. Favorable well-performance revisions in 2024 and 2025 support asset productivity, but no comparable competitor cost curve establishes persistent superiority. Management's decade-plus drilling inventory and merger synergy statements remain claims or targets.","risks":"Competition for acreage, equipment and personnel can absorb efficiency gains. Regional gas discounts already impair realizations. Merger integration, infrastructure constraints and spending to replace developed inventory can erode prospective benefits.","invalidation":"Reject the prospective cost-advantage thesis if comparable post-merger unit costs fail to improve after adjusting for production mix, the targeted annual synergies are not realized by year-end 2027, or subsequent well performance materially reverses favorable reserve revisions. A positive moat reassessment would require sustained comparative cost superiority and evidence that competitors cannot readily replicate it.","competitors":[],"evidenceIds":["e1","e2","e3","e4","e5"],"counterEvidenceIds":["e6","e7","e8","e9","e10"]}],"evidence":[{"id":"e1","sourceId":"filing-2","location":"Production Expenses: second-quarter versus first-quarter 2026 unit costs and merger effects","excerpt":"Production Expenses Q2 2026 Q1 2026 Change LOE $ 626 $ 486 29 % Gathering, processing & transportation 391 191 105 % Production taxes 357 205 74 % Property taxes 19 12 58 % Total $ 1,393 $ 894 56 % Per Boe: LOE $ 5.06 $ 6.48 -22 % Gathering, processing & transportation $ 3.16 $ 2.54 24 % Percent of oil, gas and NGL sales: Production taxes 7.0 % 6.9 % 1 % Production expenses increased primarily due to the Merger closing on May 7, 2026."},{"id":"e2","sourceId":"filing-1","location":"Reserves: 2025 revisions other than price","excerpt":"Revisions Other Than Price 2025 – Total revisions other than price (150 MMBoe) are the result of upward revisions due to well performance exceeding previous estimates on proved developed reserves (163 MMBoe) and downward revisions to proved undeveloped reserves (-13 MMBoe) as noted below."},{"id":"e3","sourceId":"filing-1","location":"Reserves: 2024 revisions other than price","excerpt":"2024 – Total revisions other than price (75 MMBoe) are the result of upward revisions due to well performance exceeding previous estimates on proved developed reserves (81 MMBoe) and downward revisions to proved undeveloped reserves (-6 MMBoe) as noted below."},{"id":"e4","sourceId":"filing-3","location":"Stockholder letter: management's Delaware Basin production, cash flow and drilling inventory claims","excerpt":"This industry-leading, high-margin position will generate more than half of our total production and cash flow, and it’s backed by more than a decade’s worth of top-tier drilling inventory."},{"id":"e5","sourceId":"filing-2","location":"Second-quarter performance highlights: prospective merger synergy target","excerpt":"• On track to deliver $1.0 billion of annual pre-tax merger synergies by year-end 2027."},{"id":"e6","sourceId":"filing-1","location":"Risk Factors: competition throughout the oil and gas industry","excerpt":"Competition for Assets, Materials, People and Capital Can Be Significant Strong competition exists in all sectors of the oil and gas industry."},{"id":"e7","sourceId":"filing-1","location":"Risk Factors: competition in marketing oil, gas and NGLs","excerpt":"Competition is also prevalent in the marketing of oil, gas and NGLs."},{"id":"e8","sourceId":"filing-1","location":"Risk Factors: competitors with greater resources and potentially superior positions","excerpt":"Certain of our competitors have resources substantially greater than ours and may have established superior strategic long-term positions and relationships."},{"id":"e9","sourceId":"filing-1","location":"Production Expenses: 2025 versus 2024 unit costs","excerpt":"Production Expenses 2025 2024 Change LOE $ 1,922 $ 1,574 22 % Gathering, processing & transportation 831 790 5 % Production taxes 748 748 0 % Property taxes 66 71 -7 % Total $ 3,567 $ 3,183 12 % Per Boe: LOE $ 6.27 $ 5.83 8 % Gathering, processing & transportation $ 2.71 $ 2.93 -8 % Percent of oil, gas and NGL sales: Production taxes 6.7 % 6.7 % 0 % Production expenses increased in 2025 primarily due to increased activity in the Rockies related to the Grayson Mill acquisition in addition to new well activity in the Delaware Basin."},{"id":"e10","sourceId":"filing-2","location":"Realized Prices: index movements, regional gas differentials and negative Waha spot pricing","excerpt":"Unhedged oil and NGL prices increased primarily due to higher WTI and Mont Belvieu index prices, while unhedged gas prices decreased primarily due to lower Henry Hub index prices and expanded regional gas price differentials in the Permian, including negative spot pricing at the Waha hub in the second quarter of 2026."},{"id":"e11","sourceId":"filing-2","location":"Realized Prices: second-quarter and first-quarter 2026 prices, benchmark realizations and hedge effects","excerpt":"Realized Prices Q2 2026 Realization Q1 2026 Change Oil (per Bbl) WTI index $ 92.47 $ 72.10 28 % Realized price, unhedged $ 95.10 103% $ 69.66 37 % Cash settlements $ (7.01 ) $ (1.72 ) Realized price, with hedges $ 88.09 95% $ 67.94 30 % Q2 2026 Realization Q1 2026 Change Gas (per Mcf) Henry Hub index $ 2.90 $ 5.05 -43 % Realized price, unhedged $ 0.35 12% $ 1.66 -79 % Cash settlements $ 0.70 $ 0.02 Realized price, with hedges $ 1.05 36% $ 1.68 -38 % Q2 2026 Realization Q1 2026 Change NGLs (per Bbl) WTI index $ 92.47 $ 72.10 28 % Realized price, unhedged $ 22.70 25% $ 17.80 28 % Cash settlements $ — $ — Realized price, with hedges $ 22.70 25% $ 17.80 28 % Q2 2026 Q1 2026 Change Combined (per Boe) Realized price, unhedged $ 41.30 $ 39.70 4 % Cash settlements $ (0.94 ) $ (0.76 ) Realized price, with hedges $ 40.36 $ 38.94 4 % From the first quarter of 2026 to the second quarter of 2026, realized prices contributed to a $918 million increase in earnings."},{"id":"e12","sourceId":"filing-2","location":"Revenue recognition: customer revenues and long-term natural gas performance obligations","excerpt":"Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Oil $ 4,354 $ 2,174 $ 6,777 $ 4,588 Gas 104 178 309 487 NGL 648 358 997 761 Oil, gas and NGL sales 5,106 2,710 8,083 5,836 Oil 1,411 859 2,412 1,777 Gas 156 246 410 517 NGL 330 233 606 468 Marketing and midstream revenues 1,897 1,338 3,428 2,762 Total revenues from contracts with customers $ 7,003 $ 4,048 $ 11,511 $ 8,598 Transaction Price Allocated to Remaining Performance Obligations As of June 30, 2026, Devon had $5.3 billion of unsatisfied performance obligations related to natural gas sales that have a fixed pricing component and a contract term greater than one year."},{"id":"e13","sourceId":"filing-2","location":"Revenue recognition: merger-assumed obligations and expected 13-year recognition period","excerpt":"These obligations were assumed by Devon in connection with the Merger and are expected to be recognized ratably over the next 13 years."},{"id":"e14","sourceId":"filing-1","location":"Field-Level Cash Margin: 2025 and 2024 asset-level results","excerpt":"2025 $ per BOE 2024 $ per BOE Field-level cash margin (Non-GAAP) Delaware Basin $ 4,636 $ 25.74 $ 5,197 $ 30.56 Rockies 1,652 $ 23.20 1,122 $ 28.61 Eagle Ford 853 $ 35.96 1,150 $ 39.72 Anadarko Basin 468 $ 15.54 464 $ 15.50 Other 47 N/M 60 N/M Total $ 7,656 $ 24.97 $ 7,993 $ 29.63 DD&A and Asset Impairments 2025 2024 Change Oil and gas per Boe $ 11.35 $ 11.70 -3 % Oil and gas $ 3,479 $ 3,156 10 % Other property and equipment 116 99 17 % Total DD&A $ 3,595 $ 3,255 10 % Asset impairments $ 254 $ — N/M DD&A increased in 2025 primarily due to higher volumes driven by the Grayson Mill acquisition and new well activity in the Delaware Basin."},{"id":"e15","sourceId":"filing-1","location":"Risk Factors: hedging contracts constrain participation in commodity price increases","excerpt":"To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we will be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts."},{"id":"e16","sourceId":"filing-3","location":"Appendix: operating cash flow, debt, cash balances and cash return on capital employed","excerpt":"​ (dollar amounts in millions) ​ ​ 2025 ​ ​ 2024 ​ ​ Cash Return on Capital Employed (CROCE) (Non-GAAP) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cash flow from operating activities (GAAP) ​ ​ ​ $ 6,711 ​ ​ ​ ​ $ 6,600 ​ ​ ​ Changes in assets and liabilities, net ​ ​ ​ ​ (151) ​ ​ ​ ​ ​ 217 ​ ​ ​ Cash flow from operating activities before B/S changes (Non-GAAP) ​ ​ ​ ​ 6,560 ​ ​ ​ ​ ​ 6,817 ​ ​ ​ Net financing costs (GAAP) ​ ​ ​ ​ 455 ​ ​ ​ ​ ​ 363 ​ ​ ​ Noncash net premium and issuance cost amortization ​ ​ ​ ​ 6 ​ ​ ​ ​ ​ 20 ​ ​ ​ Adjusted net financing costs (Non-GAAP) ​ ​ ​ ​ 461 ​ ​ ​ ​ ​ 383 ​ ​ ​ Tax benefit imputed (based on 23% and 21%, respectively) ​ ​ ​ ​ (106) ​ ​ ​ ​ ​ (80) ​ ​ ​ After-tax net financing costs (Non-GAAP) ​ ​ ​ ​ 355 ​ ​ ​ ​ ​ 303 ​ ​ ​ Adjusted cash flow (Non-GAAP)1 – (a) ​ ​ ​ ​ 6,915 ​ ​ ​ ​ ​ 7,120 ​ ​ ​ Total capitalization – beginning balance: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short and long-term debt (GAAP) ​ ​ ​ $ 8,883 ​ ​ ​ ​ $ 6,155 ​ ​ ​ Total stockholders’ equity attributable to Devon (GAAP) ​ ​ ​ ​ 14,496 ​ ​ ​ ​ ​ 12,061 ​ ​ ​ Cash, cash equivalents and restricted cash (GAAP) ​ ​ ​ ​ (846) ​ ​ ​ ​ ​ (875) ​ ​ ​ Total capitalization – beginning balance (Non-GAAP) ​ ​ ​ ​ 22,533 ​ ​ ​ ​ ​ 17,341 ​ ​ ​ Total capitalization – ending balance: ​ ​ ​ ​ ​ ​ ​ ​ ​ Short and long-term debt (GAAP) ​ ​ ​ ​ 8,389 ​ ​ ​ ​ ​ 8,883 ​ ​ ​ Total stockholders’ equity attributable to Devon (GAAP) ​ ​ ​ ​ 15,528 ​ ​ ​ ​ ​ 14,496 ​ ​ ​ Cash, cash equivalents, and restricted cash (GAAP) ​ ​ ​ ​ (1,434) ​ ​ ​ ​ ​ (846) ​ ​ ​ Total capitalization – ending balance (Non-GAAP) ​ ​ ​ ​ 22,483 ​ ​ ​ ​ ​ 22,533 ​ ​ ​ Average total capitalization (Non-GAAP)2 – (b) ​ ​ ​ $ 22,508 ​ ​ ​ ​ $ 19,937 ​ ​ ​ CROCE (Non-GAAP) – (a) / (b) ​ ​ ​ ​ 31% ​ ​ ​ ​ ​ 36% ​ ​ ​ ​ 1 Sum of cash flow from operating activities before balance sheet changes, and after-tax net financing costs."},{"id":"e17","sourceId":"filing-2","location":"Second-quarter performance highlights: completed debt retirement and share repurchases","excerpt":"• Retired $500 million of debt. • Announced a new $8.0 billion share repurchase program and have repurchased approximately 4.4 million of our common shares for approximately $202 million, or $45.48 per share, since inception of the plan after closing of the Merger."},{"id":"e18","sourceId":"filing-2","location":"Second-quarter performance highlights: dividends and federal acreage acquisition spending","excerpt":"• Paid dividends of $366 million. • Acquired approximately 16,300 net acres for approximately $2.6 billion through a federal lease sale, expanding our premier position in the Permian Basin."},{"id":"e19","sourceId":"filing-2","location":"Merger consideration: shares issued to Coterra stockholders","excerpt":"Consequently, Devon issued approximately 532 million shares of Devon common stock to holders of Coterra common stock to effect the Merger on May 7, 2026."},{"id":"e20","sourceId":"filing-2","location":"Market Risk: total debt at June 30, 2026","excerpt":"Interest Rate Risk At June 30, 2026, we had total debt of $11.4 billion."},{"id":"e21","sourceId":"filing-3","location":"Executive Compensation: approved 2025 long-term incentive allocation","excerpt":"The Committee also determined that the pursuit of strategic Company goals and creation of stockholder value would again be promoted by linking 60% of the LTI awarded for the 2025 year to Company performance and 40% to long-term stock ownership, thereby strengthening the alignment between interests of executives and stockholders."},{"id":"e22","sourceId":"filing-3","location":"Executive Compensation: performance share units and time-based restricted stock actually granted","excerpt":"Accordingly, the two types of LTI granted to NEOs were PSUs and time-based RSAs, respectively."},{"id":"e23","sourceId":"filing-1","location":"Share-Based Compensation: grants, vesting, forfeitures and TSR-dependent potential awards","excerpt":"Restricted Stock Awards & Units Performance Share Units Awards/Units Weighted Average Grant-Date Fair Value Units Weighted Average Grant-Date Fair Value (Thousands, except fair value data) Unvested at 12/31/24 4,107 $ 45.31 1,179 $ 67.38 Granted 2,679 $ 34.11 510 $ 45.92 Vested (1,897 ) $ 41.21 (272 ) $ 68.68 Forfeited (236 ) $ 40.22 (124 ) $ 65.47 Unvested at 12/31/25 4,653 $ 40.79 1,293 (1) $ 58.82 (1) A maximum of 2.6 million common shares could be awarded based upon Devon’s final TSR ranking."},{"id":"e24","sourceId":"filing-2","location":"Acquisitions and Divestitures: completed Coterra merger on May 7, 2026","excerpt":"Acquisitions and Divestitures Coterra Merger On May 7, 2026, Devon completed an all-stock merger of equals with Coterra, an oil and gas exploration and production company with assets in the Permian Basin in Texas and New Mexico, the Marcellus Shale in Pennsylvania and the Anadarko Basin in Oklahoma."},{"id":"e25","sourceId":"filing-2","location":"Restructuring and Transaction Costs: recognized merger-related expenses","excerpt":"Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Restructuring $ 198 $ 9 $ 198 $ 27 Transaction costs 48 — 67 — Total $ 246 $ 9 $ 265 $ 27 In conjunction with the Merger closing, Devon recognized $198 million of restructuring expenses during the first six months of 2026 primarily related to employee severance, termination and relocation benefits and contract terminations."},{"id":"e26","sourceId":"filing-3","location":"Corporate Governance: election standards, independent director sessions and stockholder rights","excerpt":"​ ​ Highlights of Our Corporate Governance Framework ​ ​ ​ Principal Documents for Our Corporate Governance Standards ​ ​ ■ Annual election of Directors ​ ■ Majority voting in uncontested elections ​ ■ Independent Lead Director in the event the Chair of the Board is not independent ​ ■ Executive sessions of independent Directors ​ ■ Stockholder right to call a special meeting ​ ■ Proxy access right ​ ■ Board participation in succession planning ​ ​ ​ ​ ■ Corporate Governance Guidelines ​ ■ Charters for each of the Board’s Committees ​ ■ Code of Business Conduct and Ethics for all Directors, officers, and employees ​ ■ Code of Ethics for the Chief Executive Officer, Chief Financial Officer, and designated Principal Accounting Officer ​ ​ Board of Director Nominations The GEPP Committee is responsible for nominating qualified candidates to serve on the Board and reviewing their qualifications with the Board, taking into account the composition and skills of the entire Board and specifically ensuring a sufficient number of the members of the Board are financially literate."},{"id":"e27","sourceId":"filing-3","location":"Compensation Committee: actual 2025 independence and absence of interlocks","excerpt":"​ ​ Compensation Committee Interlocks and Insider Participation Throughout 2025, the Compensation Committee was solely comprised of independent Directors with no interlocking relationships as defined by applicable SEC rules."},{"id":"e28","sourceId":"filing-3","location":"SOAR Committee: completed 2025 independent reserves oversight activities","excerpt":"​ ​ ​ ​ ​ FOR 2025, THE SOAR COMMITTEE: ​ ​ ​ ■ Approved DeGolyer & MacNaughton as the Company’s independent engineering consultant for the year ended December 31, 2025; ​ ■ Reviewed the qualifications and independence of the independent engineering consultant prior to their appointment and throughout their engagement; ​ ■ Reviewed with the independent engineering consultant the scope of the annual review of the Company’s reserves; ​ ■ Met with the independent engineering consultant, with and without management, to review and consider the evaluation of the reserves and any other relevant matters with respect to such evaluation; ​ ■ Reviewed and approved any statement of reserves data or similar reserves information and any report of the independent engineering consultants regarding such reserves to be filed with any securities regulatory authorities or to be disseminated to the public; and ​ ■ Reviewed the Company’s internal procedures relating to the disclosure of reserves."},{"id":"e29","sourceId":"filing-3","location":"Executive Compensation: performance peer group, rather than established product-market competitor coverage","excerpt":"The peers are APA Corporation, ConocoPhillips, Coterra Energy Inc., Diamondback Energy, Inc., EOG Resources, Inc., Expand Energy Corporation, Occidental Petroleum Corporation, Ovintiv Inc., Permian Resources Corporation, the S&P 500 Index, and the SPDR® S&P® Oil & Gas Exploration & Production ETF."}],"changes":["No comparable previous version."],"limitations":["Assessment uses only the supplied passages. Source dates are filing dates: February 18, May 28 and August 5, 2026; they are not retrieval dates.","Competition disclosures identify generic categories. The proxy names performance peers, but that does not establish direct competitive overlap or comparative operating economics; the competitors array is therefore empty.","Operating results and contractual disclosures support numerical assessments, but all supplied sources are issuer filings. Claims of industry-leading productivity, inventory quality and sustainable synergies lack supplied comparative substantiation.","The May 2026 merger changes production mix and reporting scope. Sequential cost improvements and production growth cannot be treated as like-for-like efficiency gains or organic execution.","Long-term gas obligations demonstrate contracted demand for part of the business, but customer concentration, renewal outcomes, termination rights and customer switching costs are not supplied.","Actual incentive grants and governance practices are disclosed. Executive beneficial ownership, complete compensation safeguards and post-merger incentive outcomes remain insufficiently covered."],"qualityAssessments":[{"category":"moat","checks":[{"criterion":"structural_advantage","grade":1,"rationale":"Productive reserves and scale support operational strengths, but mixed unit cost movements and extensive commodity-market competition do not establish a defensible comparative advantage.","evidenceIds":["e1","e2","e3","e6","e7","e9"]},{"criterion":"durability","grade":1,"rationale":"Two years of favorable well-performance revisions provide some persistence. Decade-plus inventory quality and future synergies remain management claims, without demonstrated durable competitive superiority.","evidenceIds":["e2","e3","e4","e5","e8"]},{"criterion":"customer_dependency","grade":1,"rationale":"Long-term natural gas obligations support committed demand, but no dependence on Devon-specific products or costly switching is demonstrated. Competition in commodity marketing limits the inference from those contracts.","evidenceIds":["e7","e12","e13"]},{"criterion":"erosion_resilience","grade":1,"rationale":"Recent lower lease operating costs provide a partial offset, but actual gas realization weakness and higher transportation unit costs demonstrate exposure to infrastructure and commodity-market pressure. Prospective synergies have not established resilience.","evidenceIds":["e1","e5","e10","e11"]}]},{"category":"pricing_power","checks":[{"criterion":"realized_pricing","grade":1,"rationale":"Second-quarter 2026 unhedged oil realized 103% of WTI, but gas realized only 12% of Henry Hub. The filing attributes price movements primarily to benchmarks and regional differentials, supporting weak issuer-controlled pricing despite improved combined realizations.","evidenceIds":["e10","e11"]},{"criterion":"retention","grade":2,"rationale":"The $5.3 billion of fixed-component natural gas obligations expected to be recognized over 13 years supports durable contracted demand for a subset of sales. This is indirect evidence of future repeat demand, not demonstrated renewals or customer lock-in.","evidenceIds":["e12","e13"]},{"criterion":"margin_resilience","grade":2,"rationale":"Total field-level cash margin remained positive but fell from $29.63 to $24.97 per Boe in 2025. Recent lease operating cost improvement offers an offset, while transportation costs and regional gas discounts show continuing exposure. This non-GAAP field measure does not establish full-cycle profitability.","evidenceIds":["e14","e1","e10"]},{"criterion":"contractual_freedom","grade":1,"rationale":"Observed benchmark-linked realizations show limited economic freedom to set prices. Long-term gas contracts contain fixed pricing components, and hedges restrict participation in price increases. Complete sales-contract repricing and termination provisions are unavailable.","evidenceIds":["e10","e11","e12","e13","e15"]}]},{"category":"strong_management","checks":[{"criterion":"capital_discipline","grade":2,"rationale":"2025 operating cash flow of $6.711 billion, lower year-end debt and higher cash, followed by $500 million of debt retirement in second-quarter 2026, support discipline. The $2.6 billion acreage purchase, 532 million merger shares issued and $11.4 billion of June debt create substantial commitments whose returns are not yet established. Merger issuance acquired assets and is not itself evidence of value destruction.","evidenceIds":["e16","e17","e18","e19","e20"]},{"criterion":"incentive_alignment","grade":2,"rationale":"Actual 2025 grants allocated 60% of long-term incentives to performance and 40% to stock ownership; award records show vesting and TSR-dependent potential payouts. This supports alignment, but time-based awards, incomplete ownership coverage and untested post-merger outcomes prevent a stronger conclusion. These are historical grants, not assumed approval of a pending proposal.","evidenceIds":["e21","e22","e23"]},{"criterion":"execution","grade":3,"rationale":"Favorable well-performance reserve revisions in consecutive years, completed merger execution and actual debt retirement support strong demonstrated execution. Reserve revisions are indirect operating evidence; merger completion does not establish integration success, and recognized restructuring costs and unrealized synergy targets remain material qualifications.","evidenceIds":["e2","e3","e17","e24","e25","e5"]},{"criterion":"governance","grade":3,"rationale":"Disclosed annual elections, majority voting, stockholder meeting and proxy access rights, actual independent compensation committee service, and documented reserves oversight provide strong process evidence. These practices do not prove exceptional governance outcomes or establish every post-merger board safeguard.","evidenceIds":["e26","e27","e28"]}]}],"qualityPolicy":"quality-scores-2","basisHash":"8af2338195f008e1250fdeb8d25436a324b5240c30ea2f7d0e79c500ec5641d7","updatedAt":"2026-10-17T23:47:44.164Z","sources":[{"id":"filing-1","url":"https://www.sec.gov/Archives/edgar/data/1090012/000119312526056485/dvn-20251231.htm","publishedAt":"2026-02-18","sha256":"db54048fc02b920759c310c4c4e94095ca83731de855c77e635e889dda7411a8","dateKind":"filed"},{"id":"filing-2","url":"https://www.sec.gov/Archives/edgar/data/1090012/000119312526334340/dvn-20260630.htm","publishedAt":"2026-08-05","sha256":"1b667a20e2a590004152ec99fe7eabebbfaefa89d69804615cf83a2625fc8f1a","dateKind":"filed"},{"id":"filing-3","url":"https://www.sec.gov/Archives/edgar/data/1090012/000110465926067065/tm261373-2_def14a.htm","publishedAt":"2026-05-28","sha256":"e13c738feb25923de5503413a3b4c01e659fae9474a607fe78029ce767bcb090","dateKind":"filed"}],"model":"gpt-6.1-sol","providerId":"codex:886ff908e208d1032cb94bccd8cf9d7fbd0e11dbb725cb71de3fa5eae2e2b03a","usage":{"input_tokens":56921,"cached_input_tokens":20992,"cache_write_input_tokens":0,"output_tokens":3567,"reasoning_output_tokens":197}},"signals":[{"period":"2021","end":"2021-12-31","values":{"gross_margin":null,"operating_margin":null,"roic":null,"fcf_margin":21.163636363636364,"sbc_revenue":0.72},"issues":{"peg":"Prior-year TTM earnings per diluted share is zero or negative; 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