COP ConocoPhillips 10-Q 2026-09-30 section summaries

ConocoPhillips — Q3 and first nine months of 2026

Consolidated results

Q3 total revenues and other income grew 29.2% year over year; 9M growth was 17.5%. Sales and other operating revenues grew 29.3% in Q3 and 19.3% for 9M. Higher equity earnings and disposition gains also contributed to total revenue and other income: Q3 equity earnings were $448M versus $345M and disposition gains were $54M versus $3M. For 9M, equity earnings were $934M versus $1.052B and disposition gains were $73M versus $399M.

Q3 segment results

ConocoPhillips evaluates segments based on net income. Lower 48 remained the largest revenue and earnings contributor; Alaska, EMENA and Asia Pacific also posted higher Q3 net income, while Canada’s declined.

Q3 capital expenditures and investments were $3.133B versus $2.866B; 9M spending was $9.105B versus $9.530B, concentrated in Lower 48 ($4.844B versus $5.089B) and Alaska ($2.797B versus $2.785B).

Revenue by product

For 9M, crude oil revenue was $37.488B versus $30.371B, while natural gas revenue was $6.578B versus $6.782B.

Cash flow and capital allocation

Receivables used $1.974B of cash in 9M, compared with providing $921M in 9M 2025. Asset-disposition proceeds were $1.756B versus $1.632B. Q3 dividends declared were $1.007B ($0.84 per share), compared with $975M ($0.78 per share); Q3 repurchases were $2.401B. Common shares outstanding were approximately 1,182.335M at September 30, 2026, compared with 1,225.168M at December 31, 2025.

Balance sheet and debt

The company reported total debt of $23.3B, compared with $23.4B at year-end 2025. Q3 included a $600M remarketing of 2017D bonds at 3.0%, subject to mandatory tender on July 2, 2029; $67M principal amount of 6.875% debentures was retired in Q1. Holders may redeem $283M of variable-rate demand bonds on any business day; management said it can and intends to refinance them long-term if redeemed.

Developments, exposures and other items

In Q3, ConocoPhillips sold noncore Lower 48 assets for approximately $1.7B net proceeds, with no material gain or loss. In July it agreed to acquire a 42% direct interest in a non-operated joint venture redeveloping four producing fields in northern Iraq for $400M before adjustments, including $200M deferred for up to three years. Closing was expected by year-end, subject to approvals.

The company’s $8.5B ICSID award against Venezuela, plus interest, was upheld after an annulment appeal was dismissed. Separate ICC awards include approximately $2B plus interest for Petrozuata and Hamaca and $33M plus interest for Corocoro. By September 30, ConocoPhillips had received approximately $795M in connection with the first ICC award and continues collection actions, subject to applicable sanctions and other requirements.

Q3 tax expense included a $101M benefit from a release of unrecognized tax benefits; the effective tax rate fell to 33.1% from 41.0%, mainly reflecting jurisdictional income mix and that release. The 9M effective tax rate was 34.4% versus 37.1%.

Equity-method investment carrying values included $4.9B in Australia Pacific LNG (47.5% interest), $1.7B in Port Arthur LNG (30%) and approximately $2.0B in Qatar LNG investments. APLNG debt was $2.9B, due in September 2032. ConocoPhillips’ APLNG guarantees had maximum potential payments of approximately $1.620B and a $49M carrying value; Qatar LNG guarantees had no stated maximum and a $14M carrying value. APLNG also faces a dispute over a conditional reversionary interest that, if triggered, could reduce its interest in assigned assets from 100% to 55%, with potential royalty and other claims.

Environmental remediation accruals in the U.S. and Canada rose to $297M from $220M at year-end, with substantial spending expected over 30 years. Other material matters include climate-related suits, a planned appeal of a federal order concerning two California offshore platforms tied to a historical 25% lease interest, and a certified securities class action involving Concho for which ConocoPhillips is successor.

Commodity derivative effects were mixed: Q3 sales revenue included an $85M loss versus a $62M gain, while purchased commodities included a $173M gain versus a $6M loss. For 9M, sales included $173M of gains versus $146M, and purchased commodities included $16M of gains versus a $52M loss. The company does not apply hedge accounting to commodity derivatives. The filing also describes two newly issued FASB standards—on expense disaggregation and environmental-credit accounting—and says their effects are still being evaluated.

ConocoPhillips — Q3 2026

Consolidated results

Higher realized prices drove revenue growth: they contributed $3.178 billion in Q3 and $6.700 billion in 9M, partly offset by lower volumes, which reduced revenue by $281 million and $1.126 billion, respectively. Higher crude and gas prices and volumes increased purchased-commodity costs; production and operating expenses declined, primarily from efficiencies. DD&A rose mainly because of higher rates following finalized Marathon Oil purchase-price allocations and lower proved developed reserves. Q3 reported EPS was $3.34.

Segment results

Segment profit is after-tax net income. Regional revenue and earnings reflect differing exposures to prices, production, taxes and equity affiliates.

In Canada, higher prices supported earnings, but lower production, sales timing and higher Surmont royalties weighed on results. Surmont’s post-payout royalties use a 25%–40% sliding scale tied to gross revenue, allowable deductions and WTI prices. In EMEA, price gains were partly offset by tax effects from jurisdictional income mix and lower equity-affiliate earnings. Asia Pacific benefited from higher prices and affiliate earnings, particularly stronger LNG marker prices and volumes. Corporate and Other benefited from lower net interest expense and G&A, including the nonrecurrence of Marathon Oil transaction and integration costs; Q3 “Other” income also included a consolidating tax adjustment and release of unrecognized tax benefits.

Operating metrics and cash flow

Total production declined 4% year over year in Q3 and 9M; excluding closed acquisitions and dispositions, the declines were 2% in both periods. Normal field decline was the main drag, partly offset by new wells. Lower 48 9M production was 1,483 MBOED versus 1,501 MBOED. Q3 realized prices increased across crude, bitumen and gas, while Henry Hub fell 4% to $2.96/MMBtu; Brent rose 40% to $97.00/bbl and WTI 32% to $85.79/bbl. The company is unhedged, leaving earnings and cash flow exposed to commodity-price volatility. Full-year capital spending guidance remained $12.0–$12.5 billion, compared with $12.6 billion of capital expenditures and investments in 2025.

Balance sheet, liquidity and shareholder returns

Total liquidity was $15.4 billion, including $5.5 billion of available revolver capacity; an additional $1.1 billion was held in long-term debt securities. Floating-rate debt was 1% of total debt, $878 million was short-term, and there were no commercial-paper or direct revolver borrowings outstanding. Nine-month operating cash flow growth reflected higher commodity prices, partly offset by working-capital timing and lower volumes.

The company returned $3.4 billion to shareholders in Q3 through $2.4 billion of repurchases and $1.0 billion of ordinary dividends. In 9M it repurchased 45.6 million shares for $5.4 billion and paid $2.52 per share in ordinary dividends, versus $2.34 in 9M 2025. The repurchase authorization allows up to $65 billion in aggregate; cumulative repurchases since the program began were 531.7 million shares for $44.7 billion. In November, ConocoPhillips raised its quarterly ordinary dividend 11%, from $0.84 to $0.93 per share.

Portfolio, projects and risks

Q3 Lower 48 noncore asset sales generated $1.7 billion net proceeds; the divested assets averaged about 24 MBOED in 2025. Total 9M asset-sale proceeds were $1.8 billion, and the Q3 sale completed the company’s $5 billion disposition target announced in 2025. In July, ConocoPhillips agreed to acquire BP’s 42% direct equity interest in a non-operated joint venture redeveloping four producing oil fields in Iraq’s Kirkuk area; closing was expected by year-end, subject to approvals. In October, it began evaluating a potential sale of its Norway business and Teesside asset, which together represented about 5% of 2025 production. The company said its announced cost reductions and margin enhancements were expected to exceed a $1 billion run-rate by year-end 2026.

Surmont Pad 104W-B reached first production ahead of schedule; Willow module fabrication was over 75% complete, with first oil targeted for early 2029. Commercial LNG offtake increased from 12.2 to 13.2 MTPA. Future contractual purchase obligations for long-term LNG offtake, vessels and other capacity increased by approximately $9 billion in 2026.

Qatar LNG production remained constrained through Q3. No physical damage or impairment indicators were identified as of September 30, but further Middle East escalation could disrupt operations, shipping, construction and supply chains; Qatar assets represented approximately 4% of 2025 production. Other material exposures include field decline, variable royalties and production-sharing terms, development costs and delays, geopolitical and regulatory changes, weather and transportation disruption, counterparty collection risk—including amounts due from Venezuela or PDVSA—and risks associated with joint ventures and portfolio transactions.

Obligor Group

The Obligor Group—ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, excluding Non-Obligated Subsidiaries—reported 9M revenue and other income of $39.795 billion, income before taxes of $9.669 billion and net income of $10.115 billion. Income before taxes included approximately $13.6 billion of expense for transactions with Non-Obligated Subsidiaries. The obligors’ cross-guarantees on publicly held debt securities are fully unconditional, joint and several.

These obligor figures are not the consolidated company balance sheet. The filing also identifies ordinary-course legal proceedings and environmental, climate-related and remediation matters.

Market Risk

For the nine months ended September 30, 2026, ConocoPhillips stated that its market-risk disclosures did not differ materially from those in Item 7A of its 2025 Form 10-K.

Disclosure Controls and Procedures

As of September 30, 2026, the CEO and CFO evaluated the company’s disclosure controls and procedures and concluded they were operating effectively. During the quarter, no changes in internal control over financial reporting materially affected, or were reasonably likely to materially affect, those controls.

COP reported no material changes to the risk factors disclosed in Item 1A of its 2025 Annual Report on Form 10-K. The previously disclosed risks remain applicable.

For Q3 2026, no ConocoPhillips officer or director adopted or terminated a Rule 10b5-1 or non-Rule 10b5-1 trading arrangement. This section reports no financial results or other business developments.