# Devon Energy Corporation (DVN): Business, Risks and Management's Discussion Devon reports on a calendar fiscal year. This narrative covers the fiscal 2025 annual report and the third quarter of 2026 (the three and nine months ended September 30, 2026). All amounts are in US dollars. ## Business *From the FY2025 Form 10-K (accession 0001193125-26-056485), updated for the Coterra merger from the Q3 2026 Form 10-Q (accession 0001193125-26-451216).* Devon Energy is an independent U.S. oil and natural gas producer. It explores for, develops and produces crude oil, natural gas and natural gas liquids (NGLs) from onshore U.S. basins and sells that production, almost all of it at market-sensitive prices, to purchasers under short- and long-term contracts. Revenue comes overwhelmingly from those commodity sales: in the third quarter of 2026, oil, gas and NGL sales were $5.94 billion (oil $4.31 billion, NGLs $836 million, gas $796 million), alongside $1.84 billion of marketing and midstream revenues. Total revenues, which also include the results of commodity hedges, were $6.86 billion. Devon reports a single segment, and all of its exploration and production is in the U.S. Since its merger with Coterra Energy closed on May 7, 2026, Devon has had five core areas: the Permian Basin, the Rockies, the Eagle Ford, the Anadarko Basin and the Marcellus Shale. Coterra brought acreage in the Permian Basin of Texas and New Mexico, the Marcellus Shale in Pennsylvania and the Anadarko Basin in Oklahoma. The Permian is the anchor. In the third quarter of 2026 it produced 901 MBoe/d of the company's 1,668 MBoe/d (54%), including 389 MBbls/d of the company's 553 MBbls/d of oil. The Marcellus contributed 336 MBoe/d (20%), almost all of it natural gas, followed by the Rockies (187 MBoe/d), the Anadarko (177 MBoe/d) and the Eagle Ford (61 MBoe/d). Devon agreed in October 2026 to sell the Eagle Ford (see Subsequent events). Since the closing the company has been headquartered in Houston, Texas, and it keeps a significant presence in Oklahoma City. **The asset base as of the 10-K (pre-merger, December 31, 2025).** Before the merger, Devon described four core areas: - **Delaware Basin** (southeast New Mexico and west Texas). This was the largest and most active program and the top-funded asset, targeting the Wolfcamp, Bone Spring, Avalon and Delaware formations with 11 operated rigs at year-end 2025. - **Rockies.** In the Williston Basin, the Bakken and Three Forks in North Dakota and Montana were greatly expanded by the September 2024 Grayson Mill acquisition (about $5.0 billion, including $3.5 billion of cash and about 37.3 million shares); three operated rigs ran there. In Wyoming's Powder River Basin, emerging Cretaceous oil targets (Turner, Parkman, Teapot, Niobrara) had one rig. - **Eagle Ford** (DeWitt and Karnes counties, Texas). This is an oil-weighted asset with access to Gulf Coast pricing and two rigs. On April 1, 2025, Devon dissolved its Blackhawk field partnership with BPX Energy and the two companies divided the acreage. - **Anadarko Basin** (western Oklahoma). Part of the acreage is developed jointly with Dow under a two-rig program. At year-end 2025, Devon reported proved reserves of 2,428 MMBoe (961 MMBbls of oil, 4,482 Bcf of gas and 720 MMBbls of NGLs). Proved undeveloped reserves made up 24% of the total, and DeGolyer and MacNaughton audited 91% of proved reserves. 2025 production averaged 840 MBoe/d, including 389 MBbls/d of oil. Devon held about 2.4 million net acres, roughly 1.6 million of them held by production and about 15% on federal lands. It had about 2,200 employees, all in the U.S. **How it makes money.** Production is sold at variable, market-linked prices. As of January 2026, 71% of oil volumes were sold under short-term variable contracts and 29% under long-term variable contracts, with no fixed-price oil. Devon hedges a portion of its production with swaps, basis swaps and collars. With the merger it assumed fixed-price natural gas sales contracts that carried $5.1 billion of unsatisfied performance obligations at September 30, 2026, to be recognized over about 12 years. The stated strategy rests on five principles: operating excellence, an advantaged asset portfolio, financial strength, delivering value to shareholders and a culture of innovation. Management describes the model as moderating production growth, optimizing reinvestment rates to maximize free cash flow, keeping leverage low and returning cash through a fixed dividend plus share repurchases. ## Risk factors *From the FY2025 Form 10-K (accession 0001193125-26-056485). The Q3 2026 Form 10-Q (accession 0001193125-26-451216) reports no material changes to these risk factors. Developments it discloses are noted where relevant.* The 10-K's central exposures are commodity prices, reserve replacement, regulation and the Coterra merger: - **Commodity price volatility.** Earnings, cash flow and property values depend on oil, gas and NGL prices. Over the five years before the 10-K, monthly WTI ranged from over $120 to under $50 per barrel and Henry Hub from $9.50 to $1.60 per MMBtu. Drivers named include OPEC+ and Russian output, conflicts in the Middle East and Ukraine, tariffs and trade policy, and regional price differentials in the Delaware Basin. The 10-Q adds that prices in the first nine months of 2026 were driven by conflict in the Middle East and disruptions to global oil supply. Regional gas pricing has been a live issue: negative Waha spot prices depressed second-quarter 2026 Permian gas realizations. - **Reserve estimates and replacement.** Reserve estimates require significant judgment and may be revised materially. Unconventional wells decline steeply, so production and reserves fall unless Devon keeps drilling successfully or acquiring reserves, which is capital-intensive. - **Operating hazards.** These include blowouts, well-control events, equipment failures, severe weather, limited takeaway or power, water-disposal restrictions and service shortages. Devon says it has experienced well-control events in the past, and its insurance does not cover all losses (for example, gradual pollution, war and fines). - **Hedging.** Derivatives cap upside participation and carry counterparty risk. At September 30, 2026, a 10% change in forward curves would have moved the value of Devon's net derivative position by about $625 million. - **Third parties and midstream.** Devon has limited control over non-operated properties and joint ventures, and it depends on third-party processing, gathering and pipeline capacity that can be interrupted or constrained. - **Competition** for leases, rigs, services, people and capital is intense and can be worsened by inflation and tariffs. Devon noted some increase in operating costs during 2025 from trade-policy uncertainty. - **Government regulation.** - Federal lands: the Interior Department's April 2024 leasing rule raised royalty rates, bonding and rentals, and lawsuits challenge federal permits. About 15% of Devon's acreage is federal. - Hydraulic fracturing restrictions. - Produced-water disposal and seismicity: New Mexico injection protocols, and the Railroad Commission of Texas's suspension of deep disposal permits in the Northern Culberson-Reeves area. - Taxes, including the 15% corporate alternative minimum tax. - **Climate change.** Exposures include the EPA's OOOOb/OOOOc methane rules, the methane fee (delayed to 2034), and climate-disclosure regimes in California and the EU. New York has identified Devon as a potentially responsible party under its Climate Superfund Law, although no cost-recovery demand had been received. Climate damages litigation is also a risk. The 10-Q discloses a State of Delaware climate suit that Devon intends to defend. - **Sustainability targets** may not be met and attract both "greenwashing" and "anti-ESG" scrutiny. - **Legacy and litigation exposure.** This covers royalty-underpayment suits, tax audits and liabilities from predecessor operations. According to the 10-Q: - Devon is negotiating a draft consent decree with the EPA and Department of Justice over a North Dakota air-emissions notice of violation, and other notices of violation are open in Texas and New Mexico. - Louisiana parishes are suing over coastal-zone damage tied to predecessor operations. - About $120 million is accrued for legacy decommissioning matters, including the East Bay Field in the Gulf of America, where Devon began decommissioning under an April 2026 agreement with BSEE. - The Canada Revenue Agency has issued formal assessments on prior years of the former Canadian business. Devon is contesting them, and doing so may require material cash deposits. - **Government intervention** in energy markets, such as price caps, strategic reserve releases and the EU methane import standards. - **Merger risks.** The 10-K warned that synergies might not be realized and that integration could disrupt employees, customers and contracts. It also covered the then-pending merger's operating restrictions, deal litigation, and an $865 million termination fee in some circumstances. The merger closed on May 7, 2026, and integration and synergy delivery remain the operative risks. The 10-Q adds that the merger caused an "ownership change" for Coterra under Section 382, which raises the likelihood that Devon has one within three years and could limit use of tax attributes. - **Counterparty credit,** including purchasers, joint-interest partners, hedge counterparties and buyers of divested assets who may fail to meet assumed plugging and abandonment obligations. - **Debt and ratings.** Total debt was $8.4 billion at year-end 2025 and $10.6 billion at September 30, 2026, after the Coterra notes were assumed. A downgrade would raise borrowing costs and collateral requirements. - **Cybersecurity and artificial intelligence.** Devon reports no material cyber incidents to date. Its AI-related risks include flawed outputs and data leakage. - **Shareholder activism, acquisitions and divestitures, and capital returns.** Dividends and buybacks are at the board's discretion and are not assured. ## Management's discussion: fiscal 2025 *From the FY2025 Form 10-K, Item 7 (accession 0001193125-26-056485).* Higher volumes offset lower oil prices in 2025. Net earnings were $2.7 billion, against $2.9 billion in 2024. Earnings attributable to Devon were $2.6 billion, or $4.17 per diluted share, and core earnings (non-GAAP) were $2.5 billion, or $3.92 per diluted share. Operating cash flow was $6.7 billion, and total revenues rose to $17.19 billion from $15.94 billion. - **Volumes.** Production rose 14% to 840 MBoe/d and oil rose 12% to 389 MBbls/d, mainly because of a full year of the Grayson Mill Williston assets and new Delaware Basin wells. Rockies production increased 82% to 195 MBoe/d. Higher volumes added about $1.4 billion to earnings. - **Prices.** WTI averaged $64.87 per barrel, down 14% from $75.79. Henry Hub averaged $3.43 per Mcf, up from $2.27. Realized oil fell to $62.77 per barrel unhedged, while realized gas rose to $1.67 per Mcf. Lower realized prices cut earnings by about $1.3 billion, partly cushioned by $232 million of hedge cash settlements. - **Costs and one-time items.** - Production expenses rose 12% to $3.57 billion as the Rockies grew, and lease operating expense rose to $6.27 per Boe. - Headquarters real-estate rationalization caused $254 million of asset impairments in the first quarter. - The sale of the Matterhorn pipeline investment for $409 million produced a $342 million pre-tax gain. - **Capital and returns.** - Capital expenditures were $3.59 billion, about 54% of operating cash flow. - Devon repurchased 30.8 million shares for $1.1 billion, paid $619 million of dividends and redeemed $485 million of 5.85% notes early. - It bought out the noncontrolling interests in Cotton Draw Midstream for $260 million. - **Business optimization plan.** The plan, announced in April 2025, targets $1.0 billion of annual pre-tax cash-flow improvement. About $850 million had been achieved by the end of 2025. - **Year-end position.** Liquidity was $4.4 billion ($1.4 billion of cash and $3.0 billion undrawn on the revolver). Debt was $8.4 billion, about $1.0 billion of it short-term, and debt-to-capitalization under the credit facility covenant was 24.8%. Ratings were BBB with a positive outlook (S&P), BBB+ with a positive outlook (Fitch) and Baa2 with a positive outlook (Moody's). - **2026 plan as of February 2026.** - The capital budget was $3.5 billion to $3.7 billion, about 4% below 2025. - About 30% of expected 2026 oil and gas production was hedged. - Winter weather was expected to cut first-quarter 2026 output by about 10 MBoe/d. - Buybacks were suspended under the merger agreement pending closing. About $4.5 billion of the $5.0 billion authorization had been executed through February 1, 2026. ## Fiscal 2026 to date: the Coterra merger and portfolio reshaping *From the Q3 2026 Form 10-Q (accession 0001193125-26-451216, Notes 2, 13, 14 and 17) and the merger Forms 8-K of February 2, 2026 (accession 0001193125-26-032720) and May 7, 2026 (accession 0001193125-26-211971).* In 2026 Devon went from a four-area, oil-weighted producer to a much larger multi-basin company with a large Marcellus gas business. The deal and its aftermath changed the balance sheet as follows: - **Merger terms.** Each Coterra share converted into 0.70 Devon share in an all-stock merger of equals, leaving Devon holders with about 54% of the combined company. Devon issued about 532 million shares, worth about $24.8 billion at the May 6, 2026 close of $46.60. Total consideration, including replacement equity awards, was $24.9 billion. Of the assets acquired, about $20.4 billion was allocated to proved properties and $14.0 billion to unproved properties, with $6.69 billion of deferred tax liabilities assumed. - **Capital returns after closing.** The board authorized an $8.0 billion buyback running to June 30, 2029, which replaced the old $5.0 billion program. It also raised the quarterly dividend about 33%, from $0.24 to $0.32 per share. - **Inventory added.** In May 2026 Devon paid about $2.6 billion for 16,300 net undeveloped Delaware Basin acres in Lea and Eddy counties, New Mexico, at the federal lease sale, using cash on hand. - **Debt.** Devon assumed $3.5 billion of Coterra notes and exchanged about $2.95 billion of them into Devon notes in June. In June and July it retired $1.25 billion: the $1.0 billion term loan and $250 million of 3.77% notes. No debt matures until the second quarter of 2027. - **Investments.** Fervo Energy's IPO produced a gain of about $201 million on Devon's stake in the second quarter. In the third quarter Devon paid about $83 million for a 25% interest in the Solitude gas pipeline joint venture (Permian to the Texas Gulf Coast), where it also holds firm capacity. Devon expects its total investment in Solitude to be about $500 million. ## Current quarter: Q3 2026 *From the Q3 2026 Form 10-Q (accession 0001193125-26-451216) and the third-quarter earnings release furnished on Form 8-K (accession 0001193125-26-449884).* The third quarter was the first full quarter of combined operations. Volumes rose from the second quarter, as did adjusted operating cash flow and adjusted free cash flow (both non-GAAP); GAAP operating cash flow fell. Net earnings fell from the second quarter because of hedge accounting rather than operations. - **Volumes.** - Production averaged 1,668 MBoe/d, up 23% from 1,359 MBoe/d in the second quarter. Oil averaged 553 MBbls/d (up 10%), gas 4.4 Bcf/d and NGLs 382 MBbls/d. - Marcellus output rose 60% and Anadarko 39% with a full quarter of the Coterra assets. - Eagle Ford oil fell 23% to 37 MBbls/d because of the timing of completions. - Over nine months, production averaged 1,290 MBoe/d against 836 MBoe/d a year earlier, with the Coterra legacy assets contributing about 431 MBoe/d. - **Prices.** - WTI averaged $85.63 per barrel, down from $92.47 in the second quarter. Realized oil was $79.54 per barrel with hedges. - Realized gas rose to $2.16 per Mcf with hedges, from $1.05. Unhedged gas was 66% of Henry Hub. The 10-Q attributes the gain to the larger Marcellus share moving the gas mix away from the Permian, where negative Waha pricing hurt the second quarter. The release also cites new Permian takeaway capacity narrowing Waha differentials. - Realized NGLs were $23.81 per barrel. - **Earnings.** - Net earnings attributable to Devon were $1.0 billion, or $0.88 per diluted share, against $1.9 billion in the second quarter and $687 million in the third quarter of 2025. - Against the second quarter, volumes added $669 million and prices $164 million. These gains were more than offset by a $1.26 billion swing in non-cash commodity hedge valuations (a $729 million loss after a $530 million gain) and by the absence of the second quarter's Fervo gain. - Core earnings (non-GAAP, per the release) were $1.6 billion, or $1.42 per share. - Coterra's legacy business contributed $2.16 billion of revenue and $561 million of net earnings in the quarter. - **Costs.** - Lease operating expense was $4.98 per Boe, gathering, processing and transportation $3.20 per Boe, and G&A $1.18 per Boe, down from $1.41 as volumes grew faster than overhead. - Merger restructuring and transaction costs were $69 million in the quarter and $334 million year to date. - **Cash flow and capital.** - Operating cash flow was $2.81 billion, down from $3.67 billion in the second quarter and up from $1.69 billion a year earlier. Over nine months it was $8.14 billion, up about 57%. - Capital expenditures were $1.46 billion, of which $859 million went to the Permian. - The release reports adjusted operating cash flow (non-GAAP) of $3.5 billion, up from $2.9 billion in the second quarter, and adjusted free cash flow (non-GAAP) of $2.0 billion, up from $1.7 billion. - **Shareholder returns.** Devon paid $366 million of dividends and repurchased 8.9 million shares for about $415 million at $46.96 per share; cash paid for repurchases in the quarter was $414 million. It also retired the remaining $750 million of the term loan. - **Balance sheet at September 30, 2026.** - Cash was $413 million and liquidity $3.4 billion with the undrawn $3.0 billion revolver. - Total debt was $10.6 billion at a 5.49% average fixed rate, and debt-to-capitalization under the covenant was 17.1%. - S&P now rates Devon BBB+ (stable), up from BBB (positive) at the 10-K. Fitch (BBB+, positive) and Moody's (Baa2, positive) are unchanged. - The fixed-dividend payout target is now about 10% to 15% of operating cash flow, up from about 10%. - **Hedging.** About 45% of remaining 2026 oil and 30% of gas production is hedged. For 2027, about 35% of oil and 10% of gas is hedged, excluding the Eagle Ford. - **Synergies.** The release raises the expected year-end 2026 synergy run rate to about $350 million, from a $200 million exit rate given in August, and expected 2027 synergies to about $700 million, from $600 million. The goal of at least $1.0 billion of annual pre-tax run-rate synergies by year-end 2027 is unchanged. - **Outlook (per the release).** - Full-year 2026 production and capital guidance is maintained, with the Eagle Ford included through closing. - For the fourth quarter, Devon guides to 1,660 to 1,700 MBoe/d of production, 550 to 560 MBbls/d of oil and $1,290 million to $1,395 million of capital. The 10-Q puts remaining 2026 capital at about $1.3 billion to $1.4 billion. - Initial 2027 targets, pro forma for the Eagle Ford sale, are about 525 MBbls/d of oil (growth of 1% to 3%) and 1,600 MBoe/d in total, on about $5.3 billion of capital. ## Subsequent events *From the Q3 2026 Form 10-Q, Note 2 and Liquidity (accession 0001193125-26-451216); the Form 8-K of October 8, 2026 (accession 0001193125-26-417944); and the earnings release (accession 0001193125-26-449884).* Two events after September 30, 2026 stand out, the Eagle Ford sale and the fourth-quarter dividend. Through October, cumulative buybacks also reached about $725 million. - **Eagle Ford divestiture to Crescent Energy (agreement signed October 8, 2026).** - Parties and price: Devon Energy Production Company, L.P. agreed to sell its Eagle Ford assets to Crescent (Eagle Ford) LLC, a subsidiary of Crescent Energy Company, for $4.2 billion in cash, subject to purchase price adjustments, with a July 1, 2026 effective date. - Assets: about 90,000 net acres in Karnes, DeWitt and Gonzales counties, Texas. These represent about 3% of post-merger proved reserves (10-Q) and about 4% of total BOE production (October 8 release). - Timing: closing requires Hart-Scott-Rodino clearance and customary conditions. The October 8 filing expected closing in the fourth quarter of 2026 or early 2027; the 10-Q and the November 5 release now expect early 2027. - Accounting: the assets met held-for-sale criteria on signing, and Devon expects to recognize a material gain at closing. - Proceeds: net proceeds after taxes and effective-date adjustments are expected to be about $3.5 billion, to be used for accelerated share repurchases and debt reduction. The release says Devon plans to retire a further $1.5 billion of long-term debt to reach a $9 billion gross debt target in early 2027. - **Dividend.** In November 2026 the board declared a fourth-quarter fixed dividend of $0.32 per share, about $363 million in total, payable December 30, 2026 to holders of record on December 15, 2026. - **Buybacks.** About $725 million of the $8.0 billion program had been executed through October 2026, and Devon expects fourth-quarter repurchases to exceed $1 billion. - No other post-quarter acquisitions, financings or litigation outcomes are disclosed.