# ConocoPhillips (COP) — Business, Risks and Management's Discussion Fiscal period FY26Q2 (quarter ended June 30, 2026). Sources: the FY2025 Annual Report on Form 10-K filed February 17, 2026 (accession 0001163165-26-000009) and the Quarterly Report on Form 10-Q for the quarter ended June 30, 2026, filed August 6, 2026 (accession 0001163165-26-000032). --- ## Business *From the FY2025 Form 10-K, accession 0001163165-26-000009.* ConocoPhillips is an independent exploration and production (E&P) company headquartered in Houston, Texas, with operations and activities in 14 countries. It has no refining or marketing arm: the downstream business was separated as Phillips 66 in April 2012, and the company itself was incorporated in Delaware in 2001 ahead of the 2002 Conoco/Phillips Petroleum merger. At December 31, 2025 it employed approximately 9,900 people and held total assets of about $122 billion. Full-year 2025 production was 2,375 MBOED. The portfolio spans resource-rich unconventional plays in North America, conventional assets in North America, Europe, Africa and Asia, global LNG developments, oil sands in Canada, and an inventory of global exploration prospects. At year-end 2025 the company was producing in the U.S., Norway, Canada, Australia, Malaysia, Libya, China, Qatar and Equatorial Guinea. **Segments.** Operations are managed through five operating segments defined by geography. Effective in the fourth quarter of 2025 the former Other International segment was discontinued as an operating segment and its residual results were folded into Corporate and Other, with historical segment reporting recast. Corporate and Other holds items not tied to an operating segment — most interest income and expense, corporate overhead, certain technology and licensing activities, and unrealized holding gains or losses on equity securities — and all cash, cash equivalents and short-term investments. - **Alaska** (2025: 199 MBOED; 12% of consolidated liquids, 1% of consolidated gas). The largest crude oil producer in Alaska, with major interests in the Greater Prudhoe Area (36.5% interest, Hilcorp-operated, 85 MBOED), the Greater Kuparuk Area (94.2–99.8%, operated, 75 MBOED) and the Western North Slope (100%, operated, 39 MBOED). Roughly one million net undeveloped acres of state, federal and fee exploration leases. The Willow project in the Bear Tooth Unit — three drill sites, an operations center and camp, and a processing facility — took FID in December 2023; the 2025 peak construction season covered gravel and pipeline construction and operations center hookup, with the project expected to reach near 50 percent completion in the 2026 winter season, processing-facility fabrication on schedule for transport to the North Slope in 2027, and first oil anticipated in early 2029. The company holds a 29.5% interest in the Trans-Alaska Pipeline System and moves North Slope crude to west-coast refineries using five company-owned double-hulled tankers. - **Lower 48** (2025: 1,484 MBOED; 67% of consolidated liquids, 74% of consolidated gas) — the largest segment, overwhelmingly unconventional and short-cycle. Delaware Basin (~782,000 net acres, 661 MBOED, ten rigs and three frac crews on average in 2025), Eagle Ford (~489,000 net acres, 390 MBOED), Bakken/Williston (~799,000 net acres, 204 MBOED), Midland Basin (~416,000 net acres, 192 MBOED), plus other assets and centralized processing facilities in Texas and New Mexico. - **Canada** (2025: 177 MBOED; 9% of liquids, 5% of gas). Surmont, a 100%-working-interest SAGD oil sands development south of Fort McMurray, Alberta (133 MBOED of bitumen, ~684,000 net acres in the Athabasca region, two central processing facilities and a diluent recovery unit); and the liquids-rich Montney unconventional play in northeastern British Columbia (~297,000 net acres, 44 MBOED). - **Europe, Middle East and North Africa** (2025: 8% of liquids, 18% of gas). Norway (121 MBOED) centred on the operated Greater Ekofisk Area plus partner-operated Heidrun, Troll, Aasta Hansteen, Alvheim and Visund, with a 35.1% interest in the Norpipe Oil Pipeline System and a 40.25% interest in the Teesside, U.K. crude stabilization and NGL processing facility. Qatar, through a 30% interest in QatarEnergy LNG N(3) (82 MBOED) and 25% interests in the NFE4 and NFS3 joint ventures participating in the North Field East and North Field South LNG projects. Libya, through a 20.4% interest in the Waha Concession (65 MBOED, ~13 million acres onshore in the Sirte Basin, 13 producing fields). Equatorial Guinea, through the operated 64.2% Alba Unit (38 MBOED) and equity interests in Alba Plant LLC (52.2%), EG LNG (56%, a 3.7 MTPA facility) and AMPCO methanol (45%, currently offline). - **Asia Pacific** (2025: 4% of liquids, 2% of gas). Australia Pacific LNG (47.5%), a coalbed methane joint venture with Origin Energy and Sinopec supplying two fully subscribed 4.5 MTPA LNG trains on Curtis Island — 139 MBOED net, sold to Sinopec under a 20-year 7.6 MTPA agreement and to Kansai Electric under a 20-year ~1 MTPA agreement. China, via a 49% interest in the CNOOC-operated Penglai fields in Bohai Bay (34 MBOED). Malaysia, with working interests in four PSCs offshore Sabah (36 MBOED) and, from January 2025, sole operatorship of the Kebabangan Cluster — its first operated producing asset in Malaysia. **How it makes money.** Revenue comes from selling crude oil, bitumen, natural gas, NGLs and LNG into worldwide commodity markets, generally at prevailing market prices indexed and adjusted for location, quality and transportation. A Commercial organization in the U.S., Canada, Europe and Asia markets the production and also buys and sells third-party volumes to serve customer demand and use transportation and storage capacity. Beyond equity-gas LNG in Australia, Qatar and Equatorial Guinea, the company holds a 30% direct equity interest in Port Arthur Liquefaction Holdings (PALNG) Phase 1, scheduled to start up in 2027; at year-end 2025 it held commercial LNG offtake agreements in North America totalling 10.2 MTPA with offtake commencing 2026–2031 and roughly 6.7 MTPA of European regasification capacity. It is the second-largest LNG liquefaction technology provider globally by installed capacity, with its Optimized Cascade technology licensed for 28 LNG trains. Worldwide it is contractually committed to deliver approximately 9 MTPA of LNG, 820 billion cubic feet of natural gas and 175 million barrels of crude oil, under contracts expiring through 2042. **Reserves.** Net proved reserves at December 31, 2025 were 7,637 MMBOE (6,506 consolidated plus 1,131 from equity affiliates), against 7,812 MMBOE at year-end 2024 and 6,758 MMBOE at year-end 2023. The 2025 mix was 3,424 MMBOE crude oil, 1,225 MMBOE NGLs, 2,586 MMBOE natural gas (converted 6:1) and 402 MMBOE bitumen. Approximately 84 percent of proved reserves sit in OECD member countries; 31 percent are outside the U.S. Estimated proved developed reserves for consolidated operations were 4.2 billion BOE at year-end 2025, down from 4.5 billion BOE a year earlier. **Capital return framework.** The stated framework is a growing, sustainable ordinary dividend plus through-cycle share repurchases, sized to return more than 30 percent of net cash provided by operating activities across cycles. The current repurchase program dates to late 2016; in October 2024 the Board raised the authorization from $45 billion by the lesser of $20 billion or the value of shares issued for Marathon Oil, capping aggregate repurchases at $65 billion. Through December 31, 2025 the company had repurchased 486.1 million shares for $39.3 billion, with up to $25.7 billion of authority remaining. **Competition and workforce.** Each segment is described as highly competitive, with no single competitor or small group dominating; some competitors are larger and better resourced, and several are state-owned. Of the roughly 9,900 employees at year-end 2025, 62 percent were in the U.S., 16 percent in Norway, 8 percent in Canada, 4 percent in Equatorial Guinea and 3 percent in Malaysia. --- ## Risk factors *From the FY2025 Form 10-K, accession 0001163165-26-000009 (Item 1A), condensed.* **Industry risks** - *Commodity price volatility is the dominant exposure.* Sales prices for crude, bitumen, LNG, gas and NGLs are set by markets outside the company's control; over 2025 WTI ranged from a high of $80 per barrel in January to a low of $55 per barrel in December. The company is deliberately unhedged. Prolonged low prices could hit revenues, operating income, cash flows and liquidity, and would bear directly on how much dividend the Board declares and how many shares are repurchased. Lower prices also shrink what can be produced economically, reducing proved reserves and the reserve replacement ratio, and can force capital cuts, impairments or the de-booking of proved reserves. - *Resource replacement.* Reserves decline as they are produced. Sustaining the business requires replacing them organically or by acquisition, which in turn depends on securing and renewing rights to develop hydrocarbons, reservoir optimization, bringing long-lead capital-intensive projects in on budget and schedule, and operating mature properties profitably. - *Reserve estimates are imprecise.* Proved reserve volumes cannot be directly measured; material changes to underlying assumptions — including regulation and commodity prices — could cut reported volumes or trigger impairments. - *Competition*, including anticipated competition from alternative fuels and competition for materials, equipment, services and specialist personnel. - *Emissions-reduction execution risk.* The Climate-related Risk Strategy's targets depend on government policy, acceptance of carbon capture technologies, market and permitting developments, and the pace at which effective measurement and abatement technologies mature. Executing it is expected to be costly; the company expects to have to purchase emission credits or offsets, supply of which may be insufficient or expensive, and may need to shorten the economic end-of-field life of high-intensity assets and impair the associated book value. Even meeting the goals may be characterized as insufficient. - *Price controls, export limits and midstream availability.* Governments have imposed price controls and flow-rate limits and can restrict exports or imports — the January 2024 U.S. pause on new LNG export authorizations, lifted in January 2025, is cited as an example that may have an extended adverse impact on the global LNG business. Separately, the ability to sell depends on gathering, processing, compression, transportation and pipeline capacity and on diluent availability, any of which can be curtailed by weather, permitting, mechanical failure or capacity shortfalls in newer plays. - *Joint-venture control.* Many operations run through joint ventures where another partner operates or holds the voting majority, whose interests may diverge and whose risk management the company cannot direct. - *Operating hazards*, including explosions, fires, spills, severe weather, geological events, health crises, labor disputes, geopolitical escalation, armed hostilities, terrorism, piracy, sabotage and cyberattacks, plus pollutant exposure. Offshore activity carries incrementally greater technological and operational risk from higher reservoir pressures, water depths and metocean conditions. Insurance may not cover all resulting losses. **Legal and regulatory risks** - *Environmental compliance* across permitting, discharges, atmospheric emissions (including methane and CO2), carbon taxes, hazardous materials handling, and dismantlement and restoration obligations — with substantial capital, operating, maintenance and remediation spending expected to continue, and residual exposure where a buyer that assumed such obligations cannot satisfy them. - *Climate legislation and litigation.* New York and Vermont passed "polluter pays" style legislation in 2024 seeking to hold energy companies financially responsible for state climate mitigation and adaptation; other states have introduced similar measures, and legislation elsewhere would give Attorneys General, insurers and individuals a right to recover for alleged climate impacts. Regulatory direction has also whipsawed: the EPA's December 2023 methane and VOC rule was followed in 2025 by EPA moves to dismantle some climate regulations, and those policy swings create planning uncertainty and may complicate access to non-operated emissions data. Since 2017 and continuing through 2025, cities, counties and other entities across several U.S. states and territories have sued oil and gas companies including ConocoPhillips for compensatory damages and abatement of alleged climate impacts, and in 2025 a putative class action sought to hold energy companies liable for higher home insurance premiums. Amounts claimed are unspecified and the issues unprecedented; the company considers the suits meritless but expects substantial defense costs. - *Financial-market and societal pressure.* Financial institutions' net-zero pledges may lead stakeholders to self-impose limits on lending, insurance and investment, while other investors and interest groups press in the opposite direction on ESG; the stated consequence is potentially higher cost of capital. - *Political and economic developments,* including sanctions, tax and tariff changes, executive orders, leasing restrictions, payment-transparency rules, methane standards, flaring and subsurface-water-disposal restrictions, and policies curtailing LNG or crude exports. Hydraulic fracturing draws continuing political and regulatory scrutiny and is prohibited in some jurisdictions; interest groups have used ballot initiatives, contested lease sales and permit challenges, including against the Willow project. - *International exposure.* Roughly 29 percent of 2025 hydrocarbon production came from outside the U.S., and 31 percent of proved reserves at December 31, 2025 sat outside the U.S. Risks include host-government policy and taxation changes, trade disputes, conflict escalation in the Middle East and Eastern Europe, currency movements, and — in countries lacking a fully independent judiciary — difficulty enforcing agreements and exposure to expropriation. The Venezuelan government's expropriation of the company's oil assets is cited as precedent. **Other business and financial risks** - *Access to capital.* Funding has come primarily from operating cash flow, with periodic reliance on capital markets; there is no assurance financing will be available on acceptable terms or that existing debt can be repaid or refinanced as planned. Rating agencies now weigh ESG attributes, which the company says has limited impact today but could pressure ratings over time; a downgrade would raise borrowing costs. - *Counterparty credit.* Defaults by counterparties, several of them in the same cyclical industry, could impair the company's own performance, and enforcement rights may be inadequate or costly. - *Capital return program execution.* Dividends are declared at the Board's sole discretion based on cash available, results, financial condition, peer distribution levels and operating expenses; the Board may cease declaring one at any time. The repurchase program obliges no specific volume and was suspended in the 2020 downturn. Any reduction in either could hurt the share price. - *Acquisitions and divestitures.* Risks include acquired assets failing to meet expected returns (with impairment risk), inability to dispose of noncore assets on satisfactory terms, unknown or unforeseen liabilities where contractual protection or insurance is inadequate, purchaser indemnity claims on divested assets, and integration difficulty. - *Cybersecurity.* Growing threats span unauthorized access, data or system compromise including sabotage and encryption, theft of proprietary information, ransom, extortion, threats to facilities and cyber terrorism, extended through third-party cloud and IT service providers and integrated suppliers that have themselves been breached. A breach of operational technology, including industrial control and SCADA systems, could cause physical damage to production, distribution or storage assets, delay delivery to markets, and disrupt accounting for production and settlement. --- ## Management's discussion — fiscal 2025 *From the FY2025 Form 10-K, accession 0001163165-26-000009 (Item 7).* **The year in outline.** Production of 2,375 MBOED generated $19.8 billion of cash provided by operating activities. The company invested $12.6 billion in capital expenditures and investments and returned $9.0 billion to shareholders — $4.0 billion of ordinary dividends and $5.0 billion of share repurchases, together 46 percent of operating cash flow. It ended the year with cash and cash equivalents and restricted cash of $6.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion. **Consolidated results.** Sales and other operating revenues rose $4,199 million to $58,944 million. Higher volumes contributed $6,197 million — largely the Marathon Oil assets — and higher realized gas prices $824 million, partly offset by lower realized crude prices of $4,615 million and lower bitumen prices of $349 million. Equity in earnings of affiliates fell $370 million to $1,335 million on lower LNG and crude prices. Gains on dispositions rose $680 million to $731 million, mainly from the Ursa and Europa fields, Ursa Oil Pipeline Company LLC and other noncore Lower 48 assets. On the cost side, purchased commodities rose $2,313 million, production and operating expenses rose $1,580 million (including $216 million of restructuring severance), and DD&A rose $1,901 million to $11,500 million, the latter two driven mainly by the Marathon Oil assets and higher volumes. Selling, general and administrative expense fell $265 million, chiefly on the absence of $545 million of 2024 Marathon Oil transaction expenses. Net income was $7,988 million, against $9,245 million in 2024 and $10,957 million in 2023. **By segment (after-tax, in millions):** | Segment | 2025 | 2024 | 2023 | |---|---|---|---| | Alaska | 730 | 1,326 | 1,778 | | Lower 48 | 5,264 | 5,175 | 6,461 | | Canada | 741 | 712 | 402 | | Europe, Middle East and North Africa | 1,224 | 1,189 | 1,189 | | Asia Pacific | 1,167 | 1,724 | 1,961 | | Segments total | 9,126 | 10,126 | 11,791 | | Corporate and Other | (1,138) | (881) | (834) | | **Net income** | **7,988** | **9,245** | **10,957** | Alaska fell on $509 million of lower commodity prices, $151 million of higher production and operating expenses (lease operating costs, well work and restructuring severance) and $73 million of higher DD&A, partly offset by $78 million of higher volumes; production rose five MBOED on new wells and less downtime. Lower 48 gained $3,890 million from higher volumes (including Marathon Oil) and $494 million from higher disposition gains, against $1,999 million of lower prices, $1,330 million of higher DD&A and $875 million of higher production and operating expense; production rose 332 MBOED. Canada benefited from $142 million of higher volumes, $63 million of lower DD&A on year-end 2024 upward reserve revisions, $62 million of higher other income from the Surmont contingent-consideration fair value and $52 million of lower operating expense on the absence of prior-year turnaround, less $303 million of lower prices. EMENA added $296 million of higher volumes including Equatorial Guinea assets from Marathon Oil, against $185 million of lower realized prices and $88 million of higher operating expenses. Asia Pacific fell on $206 million of lower prices, $271 million of lower equity-affiliate earnings from lower LNG sales prices, and $64 million of higher exploration expense from Malaysian and Australian dry holes. Corporate and Other worsened as "Other" earnings fell $366 million, primarily on the absence of a $455 million 2024 tax benefit from utilizing foreign tax credits after the Marathon Oil acquisition, partly offset by the absence of a $147 million 2024 loss on debt extinguishment; net interest expense rose on debt assumed with Marathon Oil. **Prices and volumes.** Total realized price was $65.62 per barrel for crude (from $76.74), $21.07 per barrel for NGLs, $40.74 per barrel for bitumen (from $47.92) and $4.44 per MCF for natural gas (from $4.69). Production rose 388 MBOED or 20 percent year over year; adjusted for closed acquisitions and dispositions, the increase was 57 MBOED or 2.5 percent. **Portfolio actions.** The Marathon Oil acquisition closed in November 2024 at a value of $16.5 billion, with approximately $4.6 billion of Marathon Oil debt assumed. Asset integration completed in the first half of 2025, delivering more than $1 billion of run-rate synergies by year-end 2025 plus approximately $1 billion of one-time benefits (including $0.5 billion recognized at close from foreign tax credit utilization, the remainder cash tax benefits from net operating losses). In the second half of 2025 the company announced a further $1 billion-plus of run-rate cost reductions and margin enhancements targeted for year-end 2026 — roughly $0.8 billion from a late-2025 restructuring that reduced headcount, lease operating cost improvements and transportation and processing opportunities, and roughly $0.2 billion from margin expansion. In August 2025 it set a $5 billion disposition target for year-end 2026 and closed $3.2 billion in 2025: the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for $699 million net, the Anadarko Basin for $1.2 billion net, other noncore Lower 48 assets for $1.1 billion (a $404 million before-tax, $310 million after-tax net gain on assets carrying an aggregate net book value of $719 million), and, counting Corporate assets alongside them, approximately $1.3 billion of other noncore disposals in total. Production from the divested Lower 48 assets averaged approximately 33 MBOED in 2024. **Reserve replacement.** Reserve replacement was 80 percent in 2025, reflecting a net decrease from noncore Lower 48 dispositions and lower prices, partly offset by development drilling and extensions and discoveries. Organic reserve replacement, excluding a net decrease of 165 MMBOE from sales and purchases, was 99 percent. Over the three years ended December 31, 2025, reserve replacement was 145 percent and organic reserve replacement — excluding a net increase of 905 MMBOE from sales and purchases — was 106 percent. **Liquidity and capital structure.** Debt was $23.4 billion at December 31, 2025, down from $24.3 billion, with $1.0 billion current including finance lease payments; $0.7 billion of principal was retired at maturity during the year (3.35% Notes, 2.4% Notes and 8.2% Debentures). In February 2025 the $5.5 billion revolving credit facility was refinanced and extended to February 2030; it carries no financial-ratio or credit-rating maintenance covenants but does contain a cross-default provision tied to $200 million or more of other debt. With no commercial paper outstanding and no direct borrowings or letters of credit against it, full $5.5 billion capacity was available at year-end, giving approximately $12.5 billion of total liquidity alongside $6.5 billion of cash and $0.5 billion of short-term investments. Long-term credit ratings were Fitch "A" (affirmed November 2025), S&P "A-" and Moody's "A2", all with stable outlooks; there are no ratings triggers that would cause an automatic default. Contractual obligations to purchase goods and services totalled approximately $45.0 billion at year-end, of which $5.0 billion falls in 2026 and the remainder over 25 years, much of it LNG offtake expected to be offset by related sales receipts. **Operational milestones and outlook.** Willow completed its largest winter season; Marathon Oil assets were integrated in the Lower 48, where drilling and completion efficiency improved more than 15 percent year over year; the company became sole operator of the Kebabangan Cluster PSC in Malaysia in January 2025 and extended it to 2050; first oil was achieved at Surmont Pad 104W-A in December 2025, ahead of schedule; and the equity LNG projects at NFE and NFS in Qatar and PALNG on the U.S. Gulf Coast remained on schedule, with NFE startup expected in the second half of 2026. Commercially, an initial 5 MTPA of PALNG Phase 1 offtake was placed and a further 5 MTPA secured, taking the commercial offtake portfolio to 10 MTPA, and an agreement was signed to extend the Waha Concession in Libya through 2050 on new fiscal terms, subject to regulatory approvals. Guidance issued with the 10-K put 2026 capital expenditures at approximately $12 billion, full-year production at 2.33 to 2.36 MMBOED and DD&A at $11.7 to $11.9 billion. **Environmental and climate positioning.** Expensed environmental costs were $834 million in 2025 and are expected to be approximately $1.0 billion in each of 2026 and 2027; capitalized environmental costs were $669 million in 2025, expected at about $750 million in 2026 and $550 million in 2027. Accrued environmental costs on the balance sheet were $220 million at December 31, 2025 versus $206 million a year earlier, with a substantial share of the expenditure expected within 30 years. The company was identified as a potentially responsible party at 20 U.S. sites under CERCLA and comparable state laws. It targets a 50–60 percent reduction in GHG emissions intensity by 2030 from a 2016 baseline on both gross operated and net equity emissions, achieved its zero-routine-flaring target for heritage ConocoPhillips assets by the end of 2025, and introduced a new commitment for 2026 to keep flaring intensity below 0.75 percent of gas produced at operated assets. It has deliberately set no Scope 3 target, arguing supply-side constraints on North American and European producers would shift production elsewhere, and instead advocates an economy-wide carbon price. --- ## Current quarter — Q2 2026 *From the Form 10-Q for the quarter ended June 30, 2026, accession 0001163165-26-000032.* **The quarter in outline.** Net income was $3,931 million, or $3.23 per diluted share, against $1,971 million and $1.56 a year earlier. Sales and other operating revenues were $19,161 million versus $14,004 million. For the six months, net income was $6,114 million ($5.00 per diluted share) on revenues of $34,922 million, against $4,820 million and $30,521 million. At June 30, 2026 the company operated in 15 countries, employed approximately 9,600 people and held total assets of $124 billion. **Prices did the work; volumes went the other way.** Brent averaged $104.52 per barrel in the quarter against $67.82 a year earlier (up 54 percent) and WTI $92.79 against $63.74 (up 46 percent), as Middle East supply disruptions that began in the first quarter persisted through the second. Realized crude was $99.40 per barrel (up 55 percent) and realized bitumen $61.01 (up 55 percent), lifting the total realized price to $62.33 per BOE from $45.77. Natural gas moved the opposite way: Henry Hub averaged $2.90 per MMBTU against $3.44 (down 16 percent) as rising domestic production left a well-supplied market, and the realized gas price fell 38 percent to $2.58 per MCF. Production was 2,248 MBOED, down 143 MBOED or six percent year over year; adjusted for closed acquisitions and dispositions the decline was 98 MBOED or four percent. Six-month production was 2,278 MBOED, down 113 MBOED or five percent (57 MBOED or four percent adjusted). The primary driver in both periods was normal field decline, partly offset by new wells online in the Lower 48, Canada, Alaska, China, Australia and Libya. At the consolidated line, sales and other operating revenues rose $5,157 million in the quarter and $4,401 million for the six months, with higher crude and bitumen prices contributing $3,730 million and $3,988 million respectively, partly offset by lower volumes of $409 million and $835 million. Purchased commodities rose $1,627 million and $1,722 million on higher crude prices, partly offset by lower gas prices. Production and operating expenses fell $141 million and $371 million on increased efficiencies. DD&A rose $145 million and $305 million on higher rates, driven by higher net book values from the finalized allocation of the Marathon Oil purchase price to specific assets and by lower proved developed reserves at December 31, 2025. **By segment (after-tax, in millions):** | Segment | Q2 2026 | Q2 2025 | 6M 2026 | 6M 2025 | |---|---|---|---|---| | Alaska | 522 | 135 | 816 | 462 | | Lower 48 | 2,584 | 1,399 | 3,987 | 3,189 | | Canada | 320 | 149 | 405 | 405 | | Europe, Middle East and North Africa | 346 | 237 | 611 | 656 | | Asia Pacific | 389 | 330 | 684 | 641 | | Segments total | 4,161 | 2,250 | 6,503 | 5,353 | | Corporate and Other | (230) | (279) | (389) | (533) | | **Net income** | **3,931** | **1,971** | **6,114** | **4,820** | Alaska (185 MBOED, down 20 MBOED on normal field decline) added $480 million from higher realized prices against $78 million of lower volumes. Lower 48 (1,479 MBOED, down 29 MBOED on field decline and the 2025 dispositions) added $1,892 million from higher realized crude and NGL prices and $155 million from lower production and operating expenses on efficiencies, against $459 million from lower gas realizations, $125 million of lower volumes, the absence of a $254 million prior-year disposition gain and $112 million of higher DD&A. Canada (152 MBOED, down 39 MBOED) added $199 million from higher realized prices and sales timing against $113 million of lower volumes and a $58 million pending claim; the volume decline came from higher variable royalties at Surmont following a 2025 post-payout event and a rate increase driven by higher prices — the Surmont royalty is a sliding 25 to 40 percent of gross revenue net of allowable deductions post-payout, indexed to WTI between $55 CAD and $120 CAD — plus normal field decline, partly offset by new Montney wells. EMENA (215 MBOED, up seven MBOED on the absence of field-wide turnarounds in the Greater Ekofisk Area and better performance in Equatorial Guinea, Libya and Norway) added $151 million from higher realized prices against $18 million of lower equity-affiliate earnings and $29 million of adverse tax mix. Asia Pacific (70 MBOED, flat) added $160 million from higher realized prices against $40 million of higher taxes other than income taxes on higher crude prices. In Corporate and Other, net interest expense improved to $(84) million from $(139) million on higher interest income and higher capitalized interest, and corporate G&A improved to $(110) million from $(147) million on the absence of Marathon Oil transaction and integration expenses; "Other" declined on a consolidating tax adjustment. **Qatar.** Geopolitical tension in the Middle East, including the ongoing conflict involving Iran, has raised volatility in global energy markets and may elevate risk to regional operations, infrastructure and shipping routes. The company's Qatar LNG investments — one producing asset and two projects under construction — have not been damaged and show no indications of impairment, but production remained constrained through the second quarter of 2026. Production from the Qatar investments was approximately four percent of total company production volumes in 2025. **Cash and capital.** Operating cash flow was $7.4 billion in the quarter and $11.7 billion for the six months, against $9.6 billion in the prior-year six months, the increase driven by higher commodity prices and partly offset by working capital timing. Capital expenditures and investments were $3.0 billion in the quarter and $5,972 million for the six months (Alaska $1,861 million, Lower 48 $3,145 million, EMENA $514 million, Canada $210 million, Asia Pacific $173 million, Corporate $69 million), against $6,664 million a year earlier; over half of the quarter's spending went to flexible, short-cycle Lower 48 unconventional plays. The company returned $3.0 billion to shareholders in the quarter — $2.0 billion of repurchases and $1.0 billion of ordinary dividends. For the six months it repurchased 26.3 million shares for $3.0 billion, taking program-to-date repurchases to 512.4 million shares and $42.3 billion, and paid ordinary dividends of $1.68 per share versus $1.56 a year earlier. Proceeds from asset sales were $0.2 billion in the first six months of 2026 against $1.3 billion a year earlier. Total liquidity at June 30, 2026 was $13.2 billion: $6.6 billion of cash and cash equivalents, $1.1 billion of short-term investments and the full $5.5 billion revolving credit facility, which matures in February 2030 and had no commercial paper, direct borrowings or letters of credit against it. There were also $1.2 billion of long-term investments in debt securities. Debt was $23.3 billion against $23.4 billion at December 31, 2025, with $0.5 billion current; $67 million of 6.875% Notes was retired at maturity in the first quarter, and $283 million of variable rate demand bonds maturing through 2035 sat in long-term debt. Moody's affirmed the long-term rating in April 2026, leaving Fitch at "A", S&P at "A-" and Moody's at "A2", all stable. Direct bank letters of credit stood at $295 million against $331 million at year-end. During 2026 the company increased future contractual purchase obligations tied to long-term LNG offtake contracts and vessels, and certain other capacity obligations, by approximately $7 billion. **Portfolio and commercial moves in the quarter.** Agreements were signed to sell interests in certain noncore Lower 48 assets for approximately $1.7 billion, subject to customary closing adjustments; production from those assets averaged approximately 21 MBOED in 2025, the disposal group had a net carrying value of approximately $1.5 billion, and the transactions met held-for-sale criteria in the quarter. Together with the 2025 dispositions, these achieve the $5 billion disposition target ahead of the year-end 2026 schedule. Commercial LNG offtake was expanded from 10.2 MTPA to 12.2 MTPA through additional agreements. In June 2026 the company and a third-party operator jointly signed an agreement with the Syrian government and Syrian Petroleum Company to increase production from and further develop certain gas fields in Syria, from which no material 2026 impact is expected; Syria is now listed among the EMENA segment's operating locations. The Surmont contingent consideration arrangement from the October 2023 acquisition of the remaining 50 percent working interest from TotalEnergies EP Canada Ltd. was extinguished: its fair value was nil at December 31, 2025, and a final payment of $81 million was made during the first six months of 2026, bringing cumulative payments since the acquisition date to $0.3 billion. **Guidance.** Third-quarter 2026 production is expected to be 2.29 to 2.32 MMBOED. All full-year guidance items remain unchanged from the revised guidance issued with first-quarter 2026 results (accession 0001163165-26-000016), which cut full-year production to 2.295 to 2.325 MMBOED from the 2.33 to 2.36 MMBOED guided with the 10-K, partly on the exclusion of Qatar volumes. The 2026 operating plan capital expenditure expectation is stated as approximately $12 to $12.5 billion, revised from the approximately $12 billion guided with the 10-K, against $12.6 billion actually invested in 2025. **Restructuring wind-down.** The severance accrual fell from $378 million at December 31, 2025 to $127 million at June 30, 2026, after $31 million of additional accruals, $279 million of benefit payments and $3 million of foreign currency translation; $71 million of the closing balance is short-term. **Contingencies.** Accrued environmental costs and litigation positions are broadly unchanged from the 10-K. On Venezuela, the March 2019 ICSID award of approximately $8.7 billion (later reduced to $8.5 billion) plus interest was upheld in full when an ICSID annulment committee dismissed Venezuela's annulment application on January 22, 2025; separate ICC arbitrations produced an award of approximately $2 billion plus interest against Petróleos de Venezuela and three affiliates for Petrozuata and Hamaca, and a $33 million award plus interest for Corocoro. Cumulatively through June 30, 2026 the company has received approximately $795 million in connection with the first ICC award, and collection actions on all three awards continue. On June 9, 2026 the Interior Board of Land Appeals upheld the BSEE order requiring prior owners of Outer Continental Shelf Lease P-0166, including ConocoPhillips through legacy Phillips Petroleum's historical 25 percent interest, to decommission two offshore platforms near Carpinteria, California; the company intends to appeal while it evaluates its exposure. The Concho Resources federal securities class action, in which ConocoPhillips is named as Concho's successor, had a class certified on April 7, 2025 and is being defended. There were no material changes to the risk factors disclosed in the FY2025 10-K. --- ## Subsequent events *From the Form 10-Q for the quarter ended June 30, 2026, accession 0001163165-26-000032.* - **Kirkuk (Iraq) joint venture — pending acquisition.** In July 2026 ConocoPhillips entered into an agreement with a wholly owned subsidiary of BP p.l.c. to acquire a **42 percent direct equity holding in a non-operated joint venture** supporting the ongoing redevelopment of **four large-scale, currently producing oil fields in the Kirkuk area of northern Iraq**. The **purchase price is $0.4 billion before closing adjustments, including deferred payments of $0.2 billion payable no later than three years from the date of close**. Cash outflow at close is expected to be $0.3 billion to $0.5 billion, including reimbursement of the company's proportionate share of bp's project costs incurred from the effective date through close. The effective date is July 1, 2026, and the transaction is expected to close by the end of 2026, subject to regulatory approvals and other customary closing conditions. - **Noncore Lower 48 divestitures — closed.** The **approximately $1.7 billion** of noncore Lower 48 sales agreed in the second quarter and described above **closed in the third quarter of 2026**, meeting the company's $5 billion disposition target ahead of its year-end 2026 schedule. - **Municipal bond remarketing.** On **July 1, 2026** the company completed a **$600 million remarketing of sub-series 2017D bonds**, part of the $1 billion St. John the Baptist Parish, State of Louisiana Revenue Refunding Bonds Series 2017. The remarketed bonds bear interest at **3.0 percent** with a **mandatory tender date of July 2, 2029**; the company retains the right to remarket them at any time thereafter up to the 2037 maturity date. They were carried in long-term debt at June 30, 2026. - **Dividend.** In **August 2026** the Board declared an ordinary dividend of **$0.84 per share**, payable **September 1, 2026** to shareholders of record on **August 17, 2026**.