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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025
or

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________________ to ___________________
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)

| Delaware | 01-0562944 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |

925 N. Eldridge Parkway, Houston, TX 77079
(Address of principal executive offices) (Zip Code)
281-293-1000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading symbols | Name of each exchange on which registered
Common Stock, $.01 Par Value | COP | New York Stock Exchange
7% Debentures due 2029 | CUSIP—718507BK1 | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The registrant had 1,235,718,250 shares of common stock, $.01 par value, outstanding at September 30, 2025.

Table of Contents

| Page
Commonly Used Abbreviations | 1
Part I—Financial Information |
Item 1. Financial Statements |
Consolidated Income Statement | 2
Consolidated Statement of Comprehensive Income | 3
Consolidated Balance Sheet | 4
Consolidated Statement of Cash Flows | 5
Notes to Consolidated Financial Statements | 6
Note 1—Basis of Presentation | 6
Note 2—Inventories | 6
Note 3—Acquisitions and Dispositions | 6
Note 4—Investments and Long-Term Receivables | 9
Note 5—Debt | 9
Note 6—Suspended Wells and Exploration Expenses | 10
Note 7—Changes in Equity | 11
Note 8—Guarantees | 12
Note 9—Contingencies, Commitments and Accrued Environmental Costs | 13
Note 10—Derivative and Financial Instruments | 16
Note 11—Fair Value Measurement | 20
Note 12—Accumulated Other Comprehensive Income (Loss) | 22
Note 13—Cash Flow Information | 23
Note 14—Related Party Transactions | 23
Note 15—Employee Benefit Plans | 24
Note 16—Sales and Other Operating Revenues | 25
Note 17—Earnings Per Share | 26
Note 18—Segment Disclosures and Related Information | 26
Note 19—Income Taxes | 32
Note 20—New Accounting Standards | 32
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 55
Item 4. Controls and Procedures | 55
Part II—Other Information |
Item 1. Legal Proceedings | 55
Item 1A. Risk Factors | 55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 56
Item 5. Other Information | 56
Item 6. Exhibits | 57
Signature | 58

Commonly Used Abbreviations | Table of Contents

Commonly Used Abbreviations
The following industry-specific, accounting and other terms, and abbreviations may be commonly used in this report.

Currencies |  | Accounting |
$ or USD | U.S. dollar | ARO | asset retirement obligation
CAD | Canadian dollar | ASC | accounting standards codification
EUR | Euro | ASU | accounting standards update
GBP NOK | British pound Norwegian kroner | DD&A | depreciation, depletion and amortization
|  | EPS | earnings per share
Units of Measurement |  | FASB | Financial Accounting Standards Board
BBL | barrel |
BCF | billion cubic feet | FIFO | first-in, first-out
BOE | barrel of oil equivalent | G&A | general and administrative
MBD | thousand barrels per day | GAAP | generally accepted accounting principles
MCF | thousand cubic feet |
MM | million | LIFO | last-in, first-out
MMBOE | million barrels of oil equivalent | NPNS | normal purchase normal sale
MBOED | thousand barrels of oil equivalent per | PP&E | properties, plants and equipment
| day | VIE | variable interest entity
MMBOED | million barrels of oil equivalent per day |  |
MMBTU | million British thermal units |  |
MMCFD | million cubic feet per day | Miscellaneous |
MTPA | million tonnes per annum | CERCLA | Federal Comprehensive
|  |  | Environmental Response
Industry |  |  | Compensation and Liability Act
BLM | Bureau of Land Management | EPA | Environmental Protection Agency
CBM | coalbed methane | ESG | environmental, social and governance
CCS | carbon capture and storage | EU | European Union
E&P | exploration and production | FERC | Federal Energy Regulatory Commission
FEED | front-end engineering and design |
FID | final investment decision | GHG | greenhouse gas
FPS | floating production system | HSE | health, safety and environment
FPSO | floating production, storage and | ICC | International Chamber of Commerce
| offloading | ICSID | World Bank’s International
G&G | geological and geophysical |  | Centre for Settlement of
JOA | joint operating agreement |  | Investment Disputes
LNG | liquefied natural gas | IRS | Internal Revenue Service
NGLs | natural gas liquids | OTC | over-the-counter
OPEC | Organization of Petroleum | NYSE | New York Stock Exchange
| Exporting Countries | SEC | U.S. Securities and Exchange
PSC | production sharing contract |  | Commission
PUDs | proved undeveloped reserves | TSR | total shareholder return
SAGD | steam-assisted gravity drainage | U.K. | United Kingdom
WCS | Western Canadian Select | U.S. | United States of America
WTI | West Texas Intermediate | VROC | variable return of cash

1 | ConocoPhillips 2025 Q3 10-Q |

Financial Statements | Table of Contents

PART I. Financial Information
Item 1. Financial Statements

Consolidated Income Statement | ConocoPhillips

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Revenues and other income |  |  |  |
Sales and other operating revenues | $ | 15,031 |  | 13,041 |  | 45,552 |  | 40,509 |
Equity in earnings of affiliates | 345 |  | 441 |  | 1,052 |  | 1,265 |
Gain (loss) on dispositions | 3 |  | (2) |  | 399 |  | 86 |
Other income | 143 |  | 124 |  | 360 |  | 356 |
Total revenues and other income | 15,522 |  | 13,604 |  | 47,363 |  | 42,216 |
Costs and expenses |  |  |  |
Purchased commodities | 5,857 |  | 4,747 |  | 17,130 |  | 14,939 |
Production and operating expenses | 2,632 |  | 2,261 |  | 7,710 |  | 6,440 |
Selling, general and administrative expenses | 271 |  | 186 |  | 712 |  | 528 |
Exploration expenses | 71 |  | 70 |  | 269 |  | 284 |
Depreciation, depletion and amortization | 2,917 |  | 2,390 |  | 8,501 |  | 6,935 |
Impairments | 10 |  | — |  | 12 |  | 34 |
Taxes other than income taxes | 525 |  | 476 |  | 1,648 |  | 1,567 |
Accretion on discounted liabilities | 94 |  | 80 |  | 283 |  | 240 |
Interest and debt expense | 223 |  | 189 |  | 660 |  | 592 |
Foreign currency transaction (gain) loss | (6) |  | (28) |  | 21 |  | (37) |
Other expenses | — |  | (2) |  | 6 |  | (8) |
Total costs and expenses | 12,594 |  | 10,369 |  | 36,952 |  | 31,514 |
Income (loss) before income taxes | 2,928 |  | 3,235 |  | 10,411 |  | 10,702 |
Income tax provision (benefit) | 1,202 |  | 1,176 |  | 3,865 |  | 3,763 |
Net income (loss) | $ | 1,726 |  | 2,059 |  | 6,546 |  | 6,939 |
Net income (loss) per share of common stock (dollars) |  |  |  |
Basic | $ | 1.38 |  | 1.77 |  | 5.18 |  | 5.92 |
Diluted | 1.38 |  | 1.76 |  | 5.18 |  | 5.91 |
Weighted-average common shares outstanding (in thousands) |  |  |
Basic | 1,245,253 |  | 1,161,318 |  | 1,258,602 |  | 1,169,350 |
Diluted | 1,246,854 |  | 1,163,227 |  | 1,260,059 |  | 1,171,424 |

See Notes to Consolidated Financial Statements.

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Financial Statements | Table of Contents

Consolidated Statement of Comprehensive Income | ConocoPhillips

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Net income (loss) | $ | 1,726 |  | 2,059 |  | 6,546 |  | 6,939 |
Other comprehensive income (loss), net of tax: |  |  |  |
Defined benefit plans | 7 |  | 5 |  | 20 |  | 14 |
Unrealized holding gain (loss) on securities | 1 |  | 14 |  | 5 |  | 10 |
Foreign currency translation adjustments | (180) |  | 147 |  | 374 |  | (156) |
Unrealized gain (loss) on hedging activities | — |  | (50) |  | — |  | (40) |
Other comprehensive income (loss), net of tax | (172) |  | 116 |  | 399 |  | (172) |
Comprehensive income (loss) | $ | 1,554 |  | 2,175 |  | 6,945 |  | 6,767 |

See Notes to Consolidated Financial Statements.

3 | ConocoPhillips 2025 Q3 10-Q |

Financial Statements | Table of Contents

Consolidated Balance Sheet | ConocoPhillips

| Millions of Dollars
| September 30 2025 | December 31 2024
Assets |  |
Cash and cash equivalents | $ | 5,260 |  | 5,607 |
Short-term investments | 996 |  | 507 |
Accounts and notes receivable (net of allowance of $3 and $7, respectively) | 5,744 |  | 6,695 |
Inventories | 1,721 |  | 1,809 |
Prepaid expenses and other current assets | 2,163 |  | 1,029 |
Total current assets | 15,884 |  | 15,647 |
Investments and long-term receivables | 10,074 |  | 9,869 |
Net properties, plants and equipment (net of accumulated DD&A of $87,510 and $81,072, respectively) | 93,498 |  | 94,356 |
Other assets | 3,016 |  | 2,908 |
Total assets | $ | 122,472 |  | 122,780 |
Liabilities |  |
Accounts payable | $ | 6,245 |  | 6,044 |
Short-term debt | 1,016 |  | 1,035 |
Accrued income and other taxes | 1,939 |  | 2,460 |
Employee benefit obligations | 1,020 |  | 1,087 |
Other accruals | 1,789 |  | 1,498 |
Total current liabilities | 12,009 |  | 12,124 |
Long-term debt | 22,466 |  | 23,289 |
Asset retirement obligations and accrued environmental costs | 8,264 |  | 8,089 |
Deferred income taxes | 12,109 |  | 11,426 |
Employee benefit obligations | 950 |  | 1,022 |
Other liabilities and deferred credits | 1,751 |  | 2,034 |
Total liabilities | 57,549 |  | 57,984 |
Equity |  |
Common stock (2,500,000,000 shares authorized at $0.01 par value) |  |
Issued (2025—2,252,743,882 shares; 2024—2,250,672,734 shares) |  |
Par value | 23 |  | 23 |
Capital in excess of par | 77,701 |  | 77,529 |
Treasury stock (at cost: 2025—1,017,025,632 shares; 2024—974,806,010 shares) | (75,186) |  | (71,152) |
Accumulated other comprehensive income (loss) | (6,074) |  | (6,473) |
Retained earnings | 68,459 |  | 64,869 |
Total equity | 64,923 |  | 64,796 |
Total liabilities and equity | $ | 122,472 |  | 122,780 |

See Notes to Consolidated Financial Statements.

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Financial Statements | Table of Contents

Consolidated Statement of Cash Flows | ConocoPhillips

| Millions of Dollars
| Nine Months Ended September 30
| 2025 | 2024
Cash flows from operating activities |  |
Net income (loss) | $ | 6,546 |  | 6,939 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities |  |
Depreciation, depletion and amortization | 8,501 |  | 6,935 |
Impairments | 12 |  | 34 |
Dry hole costs and leasehold impairments | 105 |  | 48 |
Accretion on discounted liabilities | 283 |  | 240 |
Deferred taxes | 432 |  | 249 |
Distributions more (less) than income from equity affiliates | 277 |  | 545 |
(Gain) loss on dispositions | (399) |  | (86) |
Other | (203) |  | (18) |
Working capital adjustments |  |
Decrease (increase) in accounts and notes receivable | 921 |  | 656 |
Decrease (increase) in inventories | 49 |  | (100) |
Decrease (increase) in prepaid expenses and other current assets | (117) |  | (53) |
Increase (decrease) in accounts payable | (211) |  | (117) |
Increase (decrease) in taxes and other accruals | (718) |  | 395 |
Net cash provided by operating activities | 15,478 |  | 15,667 |
Cash flows from investing activities |  |
Capital expenditures and investments | (9,530) |  | (8,801) |
Working capital changes associated with investing activities | 488 |  | 195 |
Acquisition of businesses, net of cash acquired | — |  | 49 |
Proceeds from asset dispositions | 1,632 |  | 217 |
Net sales (purchases) of investments | (556) |  | (599) |
Other | (20) |  | (11) |
Net cash used in investing activities | (7,986) |  | (8,950) |
Cash flows from financing activities |  |
Repayment of debt | (851) |  | (607) |
Issuance of company common stock | (65) |  | (66) |
Repurchase of company common stock | (3,996) |  | (3,513) |
Dividends paid | (2,957) |  | (2,749) |
Other | (75) |  | (131) |
Net cash used in financing activities | (7,944) |  | (7,066) |
Effect of exchange rate changes on cash, cash equivalents and restricted cash | 146 |  | (28) |
Net change in cash, cash equivalents and restricted cash | (306) |  | (377) |
Cash, cash equivalents and restricted cash at beginning of period | 5,905 |  | 5,899 |
Cash, cash equivalents and restricted cash at end of period | $ | 5,599 |  | 5,522 |

Restricted cash of $339 million and $298 million is included in the "Other assets" line of our Consolidated Balance Sheet at September 30, 2025, and December 31, 2024, respectively.
See Notes to Consolidated Financial Statements.

5 | ConocoPhillips 2025 Q3 10-Q |

Notes to Consolidated Financial Statements | Table of Contents

Notes to Consolidated Financial Statements
Note 1—Basis of Presentation
The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips, its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report; therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2024 Annual Report on Form 10-K. Certain prior year financial statement line items have been reclassified to conform to the current year presentation.
Note 2—Inventories

| Millions of Dollars
| September 30 2025 | December 31 2024
Crude oil and natural gas | $ | 852 |  | 907 |
Materials and supplies | 869 |  | 902 |
Total inventories | $ | 1,721 |  | 1,809 |
Inventories valued on the LIFO basis | $ | 509 |  | 578 |

Note 3—Acquisitions and Dispositions
Acquisition of Marathon Oil Corporation (Marathon Oil)
In November 2024, we completed our acquisition of Marathon Oil, an independent oil and gas exploration and production company with operations across the Lower 48 and in Equatorial Guinea. At close, the transaction was valued at $16.5 billion, which primarily represented 0.255 shares of ConocoPhillips common stock exchanged for each outstanding share of Marathon Oil common stock.

Total fair value | Millions of Dollars
Value of ConocoPhillips common stock issued* | $ | 15,972 |
Cash transferred at close** | 451 |
Value attributable to Marathon Oil share-based awards | 67 |
Other liabilities incurred*** | 17 |
Total fair value | $ | 16,507 |

*Represents the fair value of approximately 143 million shares of ConocoPhillips common stock issued to Marathon Oil stockholders. The fair value is based on the number of eligible shares of Marathon Oil common stock at a 0.255 exchange ratio and ConocoPhillips' average stock price on November 22, 2024, which was $111.93.
**Cash transferred at close primarily represents funds contributed to Marathon Oil for repayment of Marathon Oil's estimated commercial paper liabilities as of the closing date.
***Liabilities incurred are related to cash settled share-based awards and payment of cash in lieu of fractional Marathon Oil shares outstanding.
The transaction was accounted for as a business combination under FASB Topic ASC 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Fair value measurements were made for acquired assets and liabilities. Adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date, as we identify new information about facts and circumstances that existed as of the acquisition date to consider. At September 30, 2025, remaining items to finalize include allocation of fair value to unproved properties. The impact of finalizing the fair value allocation is not expected to have a material impact to our consolidated financial statements.

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Notes to Consolidated Financial Statements | Table of Contents

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant and internally generated price assumptions, production profiles and operating and development cost assumptions. Debt assumed in the acquisition was valued based on observable market prices. The fair values of accounts receivable, accounts payable and most other current assets and current liabilities were determined to be equivalent to the carrying value due to their short-term nature. The acquisition, valued at $16.5 billion, was allocated to the identifiable assets and liabilities based on their estimated fair values as of the acquisition date of November 22, 2024.

Assets acquired | Millions of Dollars
Cash and cash equivalents | $ | 385 |
Accounts receivable, net | 976 |
Inventories | 302 |
Investments and long-term receivables | 562 |
Net properties, plants and equipment | 24,232 |
Other assets | 215 |
Total assets acquired | $ | 26,672 |
Liabilities assumed |
Accounts payable | $ | 1,183 |
Accrued income and other taxes | 201 |
Employee benefit obligations | 187 |
Long-term debt | 4,719 |
Asset retirement obligations | 781 |
Deferred income taxes | 2,488 |
Other liabilities | 606 |
Total liabilities assumed | $ | 10,165 |
Net assets acquired | $ | 16,507 |

With the completion of the transaction, we acquired proved properties of approximately $13 billion, with $12 billion in Lower 48 and $1 billion in Equatorial Guinea, and unproved properties of approximately $11 billion in Lower 48.
We have recognized approximately $587 million pre-tax of transaction-related costs to date, inclusive of $2 million and $42 million in the three- and nine-month periods of 2025, respectively. These non-recurring costs related primarily to employee severance and related benefits, fees paid to advisors and the settlement of share-based awards for certain Marathon Oil employees based on the terms of the Merger Agreement.

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Notes to Consolidated Financial Statements | Table of Contents

Supplemental Pro Forma (unaudited)
The following table summarizes the unaudited supplemental pro forma financial information for the three- and nine-month periods ended September 30, 2024, as if we had completed the acquisition on January 1, 2023.

| Millions of Dollars
| Three Months Ended September 30, 2024 |  | Nine Months Ended September 30, 2024
| As reported | Pro forma Marathon Oil | Pro forma combined |  | As reported | Pro forma Marathon Oil | Pro forma combined
Supplemental pro forma (unaudited) |  |  |  |  |  |  |
Total revenues and other Income | $ | 13,604 |  | 1,791 |  | 15,395 |  |  | $ | 42,216 |  | 5,049 |  | 47,265 |
Net income (loss) | 2,059 |  | 401 |  | 2,460 |  |  | 6,939 |  | 1,195 |  | 8,134 |
Earnings per share: |  |  |  |  |  |  |
Basic net income (loss) | $ | 1.77 |  |  | 1.88 |  |  | $ | 5.92 |  |  | 6.18 |
Diluted net income (loss) | 1.76 |  |  | 1.88 |  |  | 5.91 |  |  | 6.17 |

The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not necessarily indicative of the operating results that would have occurred had the transaction been completed on January 1, 2023, nor is it necessarily indicative of future operating results of the combined entity. The pro forma results do not include cost savings anticipated as a result of the transaction. The pro forma results include adjustments which relate primarily to DD&A, which is based on the unit-of-production method, resulting from the purchase price allocated to oil and gas properties as well as adjustments for tax impacts. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.
Assets Sold
In the first quarter of 2025, we sold our interests in certain noncore assets in the Lower 48 segment for net proceeds of $581 million and recognized a $64 million before-tax and $49 million after-tax gain. At the time of disposition, our interest in these assets had a net carrying value of $517 million, comprised primarily of $553 million of PP&E and $36 million of liabilities, primarily related to noncurrent AROs.
In the second quarter of 2025, we sold our interests in the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC to Shell Offshore Inc. and Shell Pipeline Company LP, respectively, for net proceeds of $718 million. We recognized a $274 million before-tax and $266 million after-tax gain for this transaction, inclusive of the reduction of our valuation allowance recognized in the first quarter of 2025. At the time of disposition, these assets, in our Lower 48 segment, had a net carrying value of $444 million, comprised of $536 million of assets, primarily $522 million of PP&E, and $92 million of liabilities, primarily related to noncurrent AROs. For tax-related impacts of this disposition, see Note 19.
Assets Held for Sale
In July 2025, we entered into an agreement to divest Lower 48 assets in the Anadarko basin for $1.3 billion, subject to customary closing adjustments. As of September 30, 2025, these assets had a net carrying value of approximately $1.2 billion, comprised primarily of PP&E. These assets met held for sale criteria in the third quarter of 2025, and as of September 30, 2025, were reclassified to "Prepaid expenses and other current assets". This transaction closed on October 1, 2025.
Planned Dispositions
In the fourth quarter of 2025, we closed or expect to close dispositions of certain noncore Lower 48 assets for approximately $0.5 billion, subject to customary closing adjustments.

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Notes to Consolidated Financial Statements | Table of Contents

Note 4—Investments and Long-Term Receivables
Australia Pacific LNG Pty Ltd. (APLNG)
In Australia, we hold a 47.5 percent shareholding interest in APLNG. At September 30, 2025, the outstanding balance of APLNG's debt was $3.4 billion under various previously entered facilities. The last principal and interest payment on these facilities is due in September 2030. See Note 8.
At September 30, 2025, the carrying value of our equity method investment in APLNG was approximately $4.8 billion.
Port Arthur LNG (PALNG)
We hold a 30 percent direct equity investment in PALNG, a joint venture for the development of a large-scale LNG facility. At September 30, 2025, the carrying value of our equity method investment in PALNG was approximately $1.6 billion.
Qatar LNG
Our equity method investments in Qatar include the following:
•QatarEnergy LNG N(3) (N3)—30 percent owned joint venture with affiliates of QatarEnergy (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field, as well as exports LNG.
•QatarEnergy LNG NFE(4) (NFE4)—25 percent owned joint venture with affiliates of QatarEnergy (70 percent) and China National Petroleum Corporation (5 percent)—participant in the North Field East LNG project.
•QatarEnergy LNG NFS(3) (NFS3)—25 percent owned joint venture with an affiliate of QatarEnergy (75 percent)—participant in the North Field South LNG project.
At September 30, 2025, the carrying value of our equity method investments in Qatar was approximately $1.6 billion.
Note 5—Debt
Our debt bal ance at September 30, 2025 was $23.5 billion, compared with $24.3 billion at December 31, 2024.
In the second quarter of 2025, the company retired $0.2 billion principal amount of our 3.35% Notes at maturity. In the first quarter of 2025, the company retired a total of $0.5 billion principal amount of debt at maturity, consisting of $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures.
In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.
Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The facility agreement calls for commitment fees on available, but unused, amounts. The facility agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.
The revolving credit facility supports our ability to issue up to $5.5 billion of commercial paper. Commercial paper is generally limited to maturities of 90 days and is included in short-term debt on our consolidated balance sheet. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at September 30, 2025, and at December 31, 2024.
We do not have any ratings triggers on any of our corporate debt that would cause an automatic default and thereby impact our access to liquidity upon downgrade of our credit ratings. If our credit ratings are downgraded from their current levels, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit ratings were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.
At September 30, 2025, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis; therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

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Notes to Consolidated Financial Statements | Table of Contents

Note 6—Suspended Wells and Exploration Expenses
The capitalized cost of suspended wells at September 30, 2025 was $209 million, an increase of $13 million from December 31, 2024.
In the second quarter of 2025, the second Slagugle appraisal well in PL891 in the Norwegian Sea was drilled and the presence of hydrocarbons was confirmed, resulting in a $77 million increase to our suspended wells costs. We also divested certain Lower 48 offshore interests in partner-operated assets, which included $31 million of suspended wells costs. See Note 3.
In the first quarter of 2025, we recognized dry hole expenses of $36 million related to certain previously suspended wells that were capitalized for a period greater than one year in our Asia Pacific segment.

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Notes to Consolidated Financial Statements | Table of Contents

Note 7—Changes in Equity

| Millions of Dollars |  |
| Common Stock |  |  |  |  |
| Par Value | Capital in Excess of Par | Treasury Stock | Accum. Other Comprehensive Income (Loss) | Retained Earnings | Total |  |
For the three months ended September 30, 2025 |  |  |  |  |  |  |  |
Balances at June 30, 2025 | $ | 23 |  | 77,643 |  | (73,899) |  | (5,902) |  | 67,707 |  | 65,572 |  |  |
Net income (loss) |  |  |  |  | 1,726 |  | 1,726 |  |  |
Other comprehensive income (loss) |  |  |  | (172) |  |  | (172) |  |  |
Dividends declared |  |  |  |  |  |  |  |
Ordinary ($0.78 per common share) |  |  |  |  | (975) |  | (975) |  |  |
Repurchase of company common stock |  |  | (1,274) |  |  |  | (1,274) |  |  |
Excise tax on share repurchases |  |  | (13) |  |  |  | (13) |  |  |
Distributed under benefit plans |  | 58 |  |  |  |  | 58 |  |  |
Other |  |  |  |  |  |  | 1 |  | 1 |  |  |
Balances at September 30, 2025 | $ | 23 |  | 77,701 |  | (75,186) |  | (6,074) |  | 68,459 |  | 64,923 |  |  |
For the nine months ended September 30, 2025 |  |  |  |  |  |  |  |
Balances at December 31, 2024 | $ | 23 |  | 77,529 |  | (71,152) |  | (6,473) |  | 64,869 |  | 64,796 |  |  |
Net income (loss) |  |  |  |  | 6,546 |  | 6,546 |  |  |
Other comprehensive income (loss) |  |  |  | 399 |  |  | 399 |  |  |
Dividends declared |  |  |  |  |  |  |  |
Ordinary ($2.34 per common share) |  |  |  |  | (2,957) |  | (2,957) |  |  |
Repurchase of company common stock |  |  | (3,996) |  |  |  | (3,996) |  |  |
Excise tax on share repurchases |  |  | (38) |  |  |  | (38) |  |  |
Distributed under benefit plans |  | 172 |  |  |  |  | 172 |  |  |
Other |  |  |  |  | 1 |  | 1 |  |  |
Balances at September 30, 2025 | $ | 23 |  | 77,701 |  | (75,186) |  | (6,074) |  | 68,459 |  | 64,923 |  |  |

| Millions of Dollars
| Common Stock |  |  |
| Par Value | Capital in Excess of Par | Treasury Stock | Accum. Other Comprehensive Income (Loss) | Retained Earnings | Total
For the three months ended September 30, 2024 |  |  |  |  |  |
Balances at June 30, 2024 | $ | 21 |  | 61,381 |  | (68,005) |  | (5,961) |  | 62,309 |  | 49,745 |
Net income (loss) |  |  |  |  | 2,059 |  | 2,059 |
Other comprehensive income (loss) |  |  |  | 116 |  |  | 116 |
Dividends declared |  |  |  |  |  |
Ordinary ($0.58 per common share) |  |  |  |  | (677) |  | (677) |
Variable return of cash ($0.20 per common share) |  |  |  |  | (233) |  | (233) |
Repurchase of company common stock |  |  | (1,168) |  |  |  | (1,168) |
Excise tax on share repurchases |  |  | (11) |  |  |  | (11) |
Distributed under benefit plans |  | 49 |  |  |  |  | 49 |
Other |  |  |  |  | 1 |  | 1 |
Balances at September 30, 2024 | $ | 21 |  | 61,430 |  | (69,184) |  | (5,845) |  | 63,459 |  | 49,881 |
For the nine months ended September 30, 2024 |  |  |  |  |  |
Balances at December 31, 2023 | $ | 21 |  | 61,303 |  | (65,640) |  | (5,673) |  | 59,268 |  | 49,279 |
Net income (loss) |  |  |  |  | 6,939 |  | 6,939 |
Other comprehensive income (loss) |  |  |  | (172) |  |  | (172) |
Dividends declared |  |  |  |  |  |
Ordinary ($1.74 per common share) |  |  |  |  | (2,045) |  | (2,045) |
Variable return of cash ($0.60 per common share) |  |  |  |  | (704) |  | (704) |
Repurchase of company common stock |  |  | (3,513) |  |  |  | (3,513) |
Excise tax on share repurchases |  |  | (31) |  |  |  | (31) |
Distributed under benefit plans |  | 127 |  |  |  |  | 127 |
Other |  |  |  |  | 1 |  | 1 |
Balances at September 30, 2024 | $ | 21 |  | 61,430 |  | (69,184) |  | (5,845) |  | 63,459 |  | 49,881 |

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Notes to Consolidated Financial Statements | Table of Contents

Note 8—Guarantees
At September 30, 2025, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.
APLNG Guarantees
At September 30, 2025, we had multiple outstanding guarantees in connection with our 47.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2025 exchange rates:
•During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee to be five years. Our maximum exposure under this guarantee is approximately $210 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At September 30, 2025, the carrying value of this guarantee was approximately $14 million.
•In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy Limited in October 2008, we agreed to reimburse Origin Energy Limited for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements. The final guarantee expires in the fourth quarter of 2041. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $610 million ($1.0 billion in the event of intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.
•We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of 11 to 20 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $580 million and would become payable if APLNG does not perform. At September 30, 2025, the carrying value of these guarantees was approximately $39 million.
QatarEnergy LNG Guarantees
We have guaranteed our portion of certain fiscal and other joint venture obligations as a shareholder in NFE4 and NFS3. These guarantees have an approximate 30-year term with no maximum limit. At September 30, 2025, the carrying value of these guarantees was approximately $14 million.
Equatorial Guinea Guarantees
We have guaranteed payment obligations as a shareholder in both Equatorial Guinea LNG Operations, S.A., a fully owned subsidiary of Equatorial Guinea LNG Holdings Limited, and Alba Plant LLC with regard to certain agreements to process third-party gas. These guarantees have approximately three years remaining, and the maximum potential future payments related to these guarantees is approximately $116 million. At September 30, 2025, the carrying value of these guarantees was approximately $4 million.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $560 million, which consist primarily of guarantees of the residual value of leased office buildings and guarantees of the residual value of corporate aircraft. These guarantees have remaining terms of one to five years and would become payable if certain asset values are lower than guaranteed amounts at the end of the lease or contract term, business conditions decline at guaranteed entities or as a result of nonperformance of contractual terms by guaranteed parties. At September 30, 2025, there was no liability recognized for these guarantees.

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Indemnifications
Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and environmental liabilities. The carrying amount recorded for these indemnification obligations at September 30, 2025, was approximately $40 million. Those related to environmental issues have terms that are generally indefinite, and the maximum amounts of future payments are generally unlimited. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. See Note 9 for additional information about environmental liabilities.
Note 9—Contingencies, Commitments and Accrued Environmental Costs
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations and record accruals for environmental liabilities based on management’s best estimates. These estimates are based on currently available facts, existing technology and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience and data released by the U.S. EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the U.S. EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits.

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We are currently participating in environmental assessments and cleanups at numerous federal Superfund and other comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries.
For remediation activities in the U.S. and Canada, our consolidated balance sheet included total accrued environmental costs of $210 million at September 30, 2025, compared with $206 million at December 31, 2024. We expect to incur a substantial amount of these expenditures within the next 30 years. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.
Litigation and Other Contingencies
We are subject to various lawsuits and claims including, but not limited to, matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations and climate change. We will continue to defend ourselves vigorously in these matters.
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at September 30, 2025, we had performance obligations secured by letters of credit of $243 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.
In 2007, the government of Venezuela expropriated ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures, as well as the offshore Corocoro development project. In response, ConocoPhillips initiated international arbitration proceedings before the ICSID. In March 2019, an ICSID tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $8.7 billion (later reduced to $8.5 billion) plus interest for the unlawful expropriation of the projects. On January 22, 2025, an ICSID annulment committee dismissed Venezuela’s application to annul the tribunal’s decision and upheld the $8.5 billion award plus interest in full. Separate arbitrations before the ICC resulted in additional awards against Petróleos de Venezuela, S.A. (PDVSA) and three of its affiliates, including an award for approximately $2 billion plus interest, for the Petrozuata and Hamaca projects, and a $33 million award, for the Corocoro project, plus interest. Cumulatively, as of September 30, 2025, the company has received approximately $793 million in connection with the first ICC award. Collection actions for all three awards are ongoing.
ConocoPhillips has ensured that all actions related to these arbitration awards meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.
Beginning in 2017, governmental and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The legal and factual issues are unprecedented; therefore, there is significant uncertainty about the scope of the claims and alleged damages and any potential impact on the company’s financial condition. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.

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Several Louisiana parishes and the State of Louisiana have filed numerous lawsuits under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips, seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. ConocoPhillips entities are defendants in several of the lawsuits and will vigorously defend against them. Because plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages), and we continue to evaluate our exposure in these lawsuits while assessing options for early resolution.
In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease P-0166 relinquished the lease and abandoned the lease platforms and facilities. BSEE’s order to ConocoPhillips is premised on its connection to Phillips Petroleum Company, a legacy company of ConocoPhillips, which held a historical 25 percent interest in this lease and operated these facilities but sold its interest approximately 30 years ago. ConocoPhillips continues to evaluate its exposure in this matter.
In July 2021, a federal securities class action was filed against Concho Resources Inc. (Concho), certain of Concho’s officers, and ConocoPhillips as Concho’s successor in the United States District Court for the Southern District of Texas. On October 21, 2021, the court issued an order appointing Utah Retirement Systems and the Construction Laborers Pension Trust for Southern California as lead plaintiffs (Lead Plaintiffs). On January 7, 2022, the Lead Plaintiffs filed their consolidated complaint alleging that Concho made materially false and misleading statements regarding its business and operations in violation of the federal securities laws and seeking unspecified damages, attorneys’ fees, costs, equitable/injunctive relief and such other relief that may be deemed appropriate. The defendants filed a motion to dismiss the consolidated complaint on March 8, 2022. On June 23, 2023, the court denied defendants’ motion as to most defendants including Concho/ConocoPhillips. On April 7, 2025, the court certified a class. We believe the allegations in the action are without merit and are vigorously defending this litigation.
ConocoPhillips is involved in pending disputes with commercial counterparties relating to the propriety of its force majeure notices following Winter Storm Uri in 2021. We believe these claims are without merit and are vigorously defending them.
Long-Term Unconditional Purchase Obligations and Commitments, Including Throughput and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements are primarily related to LNG purchase commitments. The fixed and determinable portion of the remaining estimated payments under these various agreements as of September 30, 2025 is: 2025—$2 million; 2026—$6 million; 2027—$6 million; 2028—$397 million; 2029—$558 million; and 2030 and after—$21 billion. Generally, variable components of these obligations include commodity futures prices and inflation rates. Purchases of LNG under these commitments are expected to be offset in the same or approximately same periods by cash received from the related sales transactions.

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Note 10—Derivative and Financial Instruments
We use futures, forwards, swaps and options in various markets to meet our customer needs, capture market opportunities and manage foreign exchange currency risk.
Commodity Derivative Instruments
Our commodity business primarily consists of natural gas, crude oil, bitumen, NGLs, LNG and power.
Commodity derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts and certain gas contracts. We do not apply hedge accounting for our commodity derivatives.
The following table presents the gross fair values of our commodity derivatives, excluding collateral, on our consolidated balance sheet:

| Millions of Dollars
| September 30 2025 | December 31 2024
Assets |  |
Prepaid expenses and other current assets | $ | 439 |  | 394 |
Other assets | 124 |  | 94 |
Liabilities |  |
Other accruals | 391 |  | 397 |
Other liabilities and deferred credits | 98 |  | 83 |

The gains (losses) from commodity derivatives included in our consolidated income statement are presented in the following table:

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Sales and other operating revenues | $ | 62 |  | 49 |  | 146 |  | 135 |
Other income | (3) |  | (2) |  | (6) |  | (2) |
Purchased commodities | (6) |  | (46) |  | (52) |  | (125) |

The table below summarizes our net exposures resulting from outstanding commodity derivative contracts:

| Open Position Long (Short)
| September 30 2025 | December 31 2024
Commodity |  |
Natural gas and power (BCF equivalent) |  |
Fixed price | (24) |  | (17) |
Basis | (22) |  | — |

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Interest Rate Derivative Instruments
I n 2023, PALNG executed interest rate swaps that had the effect of converting 60 percent of the projected term loans outstanding to finance the cost of development and construction of Phase 1 from floating- to fixed-rate. During the first quarter of 2025, PALNG dedesignated the remaining portion of the interest rate swaps previously designated as a cash flow hedge. Changes in the fair value of the dedesignated hedging instruments are reported in the “Equity in earnings of affiliates” line on our consolidated income statement.
For the three- and nine-month periods ended September 30, 2025, we recognized a loss of $6 million and a gain of $27 million, respectively, in “Equity in earnings of affiliates" related to the swaps. For the three- and nine-month periods ended September 30, 2024, we recognized an unrealized loss of $63 million and $50 million, respectively, in other comprehensive income (loss) related to these swaps.
Financial Instruments
We invest in financial instruments with maturities based on our cash forecasts for the various accounts and currency pools we manage. The types of financial instruments in which we currently invest include:
•Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of time.
•Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be withdrawn without notice.
•Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.
•U.S. government or government agency obligations: Securities issued by the U.S. government or U.S. government agencies.
•Foreign government obligations: Securities issued by foreign governments.
•Corporate bonds: Unsecured debt securities issued by corporations.
•Asset-backed securities: Collateralized debt securities.
The following investments are carried on our consolidated balance sheet at cost plus accrued interest, and the table reflects remaining maturities at September 30, 2025, and December 31, 2024:

| Millions of Dollars
| Carrying Amount
| Cash and cash equivalents | Short-term investments |
| September 30 2025 | December 31 2024 | September 30 2025 | December 31 2024 |  |
Cash | $ | 560 |  | 770 |  |  |  |  |
Demand deposits | 2,472 |  | 3,211 |  |  |  |  |
Time deposits |  |  |  |  |  |
1 to 90 days | 1,899 |  | 1,364 |  | 529 |  | 1 |  |  |
91 to 180 days |  |  | 6 |  | 5 |  |  |
Within one year |  |  | 21 |  | 6 |  |  |
U.S. government obligations |  |  |  |  |  |
1 to 90 days | 316 |  | 260 |  | — |  | — |  |  |
| $ | 5,247 |  | 5,605 |  | 556 |  | 12 |  |  |

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The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at September 30, 2025, and December 31, 2024:

| Millions of Dollars
| Carrying Amount
| Cash and cash equivalents | Short-term investments | Investments and long-term receivables
| September 30 2025 | December 31 2024 | September 30 2025 | December 31 2024 | September 30 2025 | December 31 2024
Major Security Type |  |  |  |  |  |
Corporate bonds | $ | — |  | — |  | 300 |  | 338 |  | 643 |  | 612 |
Commercial paper | 13 |  | 2 |  | 81 |  | 77 |  |  |
U.S. government obligations | — |  | — |  | 39 |  | 43 |  | 225 |  | 218 |
U.S. government agency obligations |  |  | — |  | — |  | 1 |  | 7 |
Foreign government obligations |  |  | 4 |  | 4 |  | 11 |  | 12 |
Asset-backed securities |  |  | 16 |  | 33 |  | 254 |  | 205 |
| $ | 13 |  | 2 |  | 440 |  | 495 |  | 1,134 |  | 1,054 |

Cash and cash equivalents and short-term investments have remaining maturities within one year. Investments and long-term receivables have remaining maturities that vary from greater than one year through 13 years.
The following table summarizes the amortized cost basis and fair value of investments in debt securities classified as available for sale:

| Millions of Dollars
| Amortized Cost Basis | Fair Value
| September 30 2025 | December 31 2024 | September 30 2025 | December 31 2024
Major Security Type |  |  |  |
Corporate bonds | $ | 936 |  | 947 |  | 943 |  | 950 |
Commercial paper | 94 |  | 79 |  | 94 |  | 79 |
U.S. government obligations | 263 |  | 262 |  | 264 |  | 261 |
U.S. government agency obligations | 1 |  | 7 |  | 1 |  | 7 |
Foreign government obligations | 15 |  | 16 |  | 15 |  | 16 |
Asset-backed securities | 269 |  | 237 |  | 270 |  | 238 |
| $ | 1,578 |  | 1,548 |  | 1,587 |  | 1,551 |

No allowance for credit losses has been recorded on investments in debt securities which are in an unrealized loss position.
For the three- and nine-month periods ended September 30, 2025, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $271 million and $782 million, respectively. For the three- and nine-month periods ended September 30, 2024, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $142 million and $597 million, respectively. Gross realized gains and losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and redeemed is determined using the specific identification method.

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Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, long-term investments in debt securities, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government money market funds, U.S. government and government agency obligations, time deposits with major international banks and financial institutions, high-quality corporate bonds, foreign government obligations and asset-backed securities. Our long-term investments in debt securities are placed in high-quality corporate bonds, asset-backed securities, U.S. government and government agency obligations and foreign government obligations.
The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared primarily with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We may require collateral to limit the exposure to loss including letters of credit, prepayments and surety bonds, as well as master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.
The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in a liability position at September 30, 2025, and December 31, 2024, was $59 million and $70 million, respectively. For these instruments, no collateral was posted at September 30, 2025, and December 31, 2024. If our credit rating had been downgraded below investment grade at September 30, 2025, we would have been required to post $25 million of additional collateral, either with cash or letters of credit.

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Note 11—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the fair value hierarchy.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. There were no material transfers into or out of Level 3 during the nine-month period ended September 30, 2025, nor during the year ended December 31, 2024.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis include our investments in debt securities classified as available for sale, commodity derivatives and our contingent consideration arrangement related to the Surmont acquisition.
•Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 financial assets also include our investments in U.S. government obligations classified as available for sale debt securities, which are valued using exchange prices.
•Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 2 financial assets also include our investments in debt securities classified as available for sale including investments in corporate bonds, commercial paper, asset-backed securities, U.S. government agency obligations and foreign government obligations that are valued using pricing provided by brokers or pricing service companies that are corroborated with market data.
•Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 commodity derivative activity was not material for all periods presented.
•Level 3 liabilities include the fair value of future quarterly contingent payments associated with the Surmont acquisition. In October 2023, we completed our acquisition of the remaining 50 percent working interest in Surmont, an asset in our Canada segment, from TotalEnergies EP Canada Ltd. The consideration for the acquisition included a contingent consideration arrangement requiring payment of up to $0.4 billion CAD over a five-year term. The contingent payments represent $2 million for every dollar that WCS pricing exceeds $52 per barrel during the month, subject to certain production targets being achieved. The undiscounted amount we could pay under this arrangement was up to $0.3 billion USD at closing.

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The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

| Millions of Dollars
| September 30, 2025 |  | December 31, 2024
| Level 1 | Level 2 | Level 3 | Total |  | Level 1 | Level 2 | Level 3 | Total
Assets |  |  |  |  |  |  |  |  |
Investments in debt securities | $ | 264 |  | 1,323 |  | — |  | 1,587 |  |  | 261 |  | 1,290 |  | — |  | 1,551 |
Commodity derivatives | 313 |  | 204 |  | 46 |  | 563 |  |  | 201 |  | 252 |  | 35 |  | 488 |
Total assets | $ | 577 |  | 1,527 |  | 46 |  | 2,150 |  |  | 462 |  | 1,542 |  | 35 |  | 2,039 |
Liabilities |  |  |  |  |  |  |  |  |
Commodity derivatives | $ | 310 |  | 131 |  | 48 |  | 489 |  |  | 275 |  | 160 |  | 45 |  | 480 |
Contingent consideration | — |  | — |  | 59 |  | 59 |  |  | — |  | — |  | 145 |  | 145 |
Total liabilities | $ | 310 |  | 131 |  | 107 |  | 548 |  |  | 275 |  | 160 |  | 190 |  | 625 |

The range and arithmetic average of the significant unobservable input used in the Level 3 fair value measurement was as follows:

| Fair Value (Millions of Dollars) | Valuation Technique | Unobservable Input | Range (Arithmetic Average)
Contingent consideration - Surmont as of: |  |  |  |
September 30, 2025 | $ | 59 |  | Discounted cash flow | Commodity price outlook* ($/BOE) | $47.53 - $55.65 ($51.25)
December 31, 2024 | 145 |  | $48.63 - $57.53 ($53.38)

*Commodity price outlook based on a combination of external pricing service companies' outlooks and internal outlook.
The fair value of the contingent consideration on the acquisition date was $320 million. We have made payments of $77 million during the nine-month period ended September 30, 2025, and $234 million in total since the acquisition under this arrangement, included in the "Other" line within the financing activities section of our consolidated statement of cash flows.
The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists.

| Millions of Dollars
|  |  | Amounts Subject to Right of Setoff
| Gross Amounts Recognized | Amounts Not Subject to Right of Setoff | Gross Amounts | Gross Amounts Offset | Net Amounts Presented | Cash Collateral | Net Amounts
September 30, 2025 |  |  |  |  |  |  |
Assets | $ | 563 |  | 1 |  | 562 |  | 378 |  | 184 |  | — |  | 184 |
Liabilities | 489 |  | 1 |  | 488 |  | 378 |  | 110 |  | 2 |  | 108 |
December 31, 2024 |  |  |  |  |  |  |
Assets | $ | 488 |  | — |  | 488 |  | 278 |  | 210 |  | — |  | 210 |
Liabilities | 480 |  | — |  | 480 |  | 278 |  | 202 |  | 73 |  | 129 |

At September 30, 2025, and December 31, 2024, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

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Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
•Cash and cash equivalents and short-term investments: The carrying amount reported on the balance sheet approximates fair value. For those investments classified as available for sale debt securities, the carrying amount reported on the balance sheet is fair value.
•Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value.
•Investments in debt securities classified as available for sale: The fair value of investments in debt securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using pricing provided by brokers or pricing service companies that are corroborated with market data. See Note 10.
•Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.
•Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.
•Commercial paper: The carrying amount of our commercial paper instruments approximates fair value and is reported on the balance sheet as short-term debt.
The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

| Millions of Dollars
| Carrying Amount |  | Fair Value
| September 30 2025 | December 31 2024 |  | September 30 2025 | December 31 2024
Financial assets |  |  |  |  |
Commodity derivatives | $ | 185 |  | 210 |  |  | 185 |  | 210 |
Investments in debt securities | 1,587 |  | 1,551 |  |  | 1,587 |  | 1,551 |
Financial liabilities |  |  |  |  |
Total debt, excluding finance leases | 22,660 |  | 23,384 |  |  | 22,878 |  | 22,997 |
Commodity derivatives | 109 |  | 129 |  |  | 109 |  | 129 |

Note 12—Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) in the equity section of our consolidated balance sheet includes:

| Millions of Dollars
| Defined Benefit Plans | Unrealized Holding Gain/(Loss) on Securities | Foreign Currency Translation | Unrealized Gain/(Loss) on Hedging Activities | Accumulated Other Comprehensive Income/(Loss)
December 31, 2024 | $ | (390) |  | 3 |  | (6,104) |  | 18 |  | (6,473) |
Other comprehensive income (loss) | 20 |  | 5 |  | 374 |  | — |  | 399 |
September 30, 2025 | $ | (370) |  | 8 |  | (5,730) |  | 18 |  | (6,074) |

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Note 13—Cash Flow Information

| Millions of Dollars
| Nine Months Ended September 30
| 2025 | 2024
Cash payments |  |
Interest | $ | 694 |  | 628 |
Income taxes | 3,896 |  | 2,797 |
Net sales (purchases) of investments |  |
Short-term investments purchased | $ | (1,230) |  | (2,562) |
Short-term investments sold | 1,136 |  | 2,357 |
Long-term investments purchased | (675) |  | (503) |
Long-term investments sold | 213 |  | 109 |
| $ | (556) |  | (599) |

For additional information on cash and non-cash changes to our consolidated balance sheet, see Note 3 regarding assets sold during the period.
Note 14—Related Party Transactions
The following tables summarize the related party balances and activities which are primarily with equity affiliates:

| Millions of Dollars
| September 30 2025 | December 31 2024 |
Balance Sheet |  |  |  |
Accounts and notes receivable | $ | 45 |  | 74 |  |  |
Accounts payable | 73 |  | 57 |  |  |

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Income Statement |  |  |  |
Operating revenues and other income | $ | 12 |  | 23 |  | 60 |  | 64 |
Purchased commodities | (2) |  | — |  | — |  | — |
Operating expenses and selling, general and administrative expenses | 84 |  | 51 |  | 242 |  | 163 |

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Note 15—Employee Benefit Plans
Pension and Postretirement Plans

| Millions of Dollars
| Pension Benefits |  | Other Benefits
| 2025 |  | 2024 |  | 2025 |  | 2024
| U.S. |  | Int'l. |  | U.S. |  | Int'l. |  |  |  |
Components of net periodic benefit cost |  |  |  |  |  |  |  |  |  |  |
Three Months Ended September 30 |  |  |  |  |  |  |  |  |  |  |
Service cost | $ | 15 |  |  | 7 |  |  | 12 |  |  | 9 |  |  | — |  |  | — |
Interest cost | 24 |  |  | 32 |  |  | 19 |  |  | 28 |  |  | 2 |  |  | 1 |
Expected return on plan assets | (20) |  |  | (46) |  |  | (16) |  |  | (41) |  |  |  |  |
Amortization of prior service cost (credit) | — |  |  | 1 |  |  | — |  |  | — |  |  | (7) |  |  | (10) |
Recognized net actuarial loss (gain) | 3 |  |  | 12 |  |  | 1 |  |  | 15 |  |  | — |  |  | — |
Net periodic benefit cost | $ | 22 |  |  | 6 |  |  | 16 |  |  | 11 |  |  | (5) |  |  | (9) |
Nine Months Ended September 30 |  |  |  |  |  |  |  |  |  |  |
Service cost | $ | 44 |  |  | 23 |  |  | 37 |  |  | 28 |  |  | 1 |  |  | 1 |
Interest cost | 70 |  |  | 94 |  |  | 57 |  |  | 85 |  |  | 6 |  |  | 4 |
Expected return on plan assets | (58) |  |  | (135) |  |  | (49) |  |  | (122) |  |  |  |  |
Amortization of prior service cost (credit) | — |  |  | 2 |  |  | — |  |  | — |  |  | (19) |  |  | (29) |
Recognized net actuarial loss (gain) | 8 |  |  | 35 |  |  | 5 |  |  | 43 |  |  | — |  |  | — |
Settlements | — |  |  | 1 |  |  | — |  |  | — |  |  |  |  |
Net periodic benefit cost | $ | 64 |  |  | 20 |  |  | 50 |  |  | 34 |  |  | (12) |  |  | (24) |

The components of net periodic benefit cost, other than the service cost component, are included in the "Other expenses" line of our consolidated income statement.
Severance Accrual
During 2025, we announced certain cost reduction initiatives. As part of these initiatives, we are anticipating a reduction in our employee workforce. Severance expense of $238 million was recorded in the third quarter of 2025 reflecting the probable and reasonably estimable portion of the related liability.
The following table summarizes our severance accrual activity for the nine-month period ended September 30, 2025:

| Millions of Dollars
Balance at December 31, 2024 | $ | 331 |
Accruals | 244
Benefit payments | (239) |
Foreign currency translation adjustment | 2 |
Balance at September 30, 2025 | $ | 338 |

Of the balance at September 30, 2025, $329 million is classified as short-term.

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Note 16—Sales and Other Operating Revenues
Revenue from Contracts with Customers
The following table provides further disaggregation of our consolidated sales and other operating revenues:

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Revenue from contracts with customers | $ | 13,337 |  | 11,703 |  | 40,437 |  | 36,670 |
Revenue from contracts outside the scope of ASC Topic 606 |  |  |  |
Physical contracts meeting the definition of a derivative | 1,758 |  | 1,403 |  | 5,173 |  | 3,971 |
Financial derivative contracts | (64) |  | (65) |  | (58) |  | (132) |
Consolidated sales and other operating revenues | $ | 15,031 |  | 13,041 |  | 45,552 |  | 40,509 |

Revenues from contracts outside the scope of ASC Topic 606, “Revenue from Contracts with Customers,” relate primarily to physical gas contracts at market prices, which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 18—Segment Disclosures and Related Information:

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment |  |  |  |
Lower 48 | $ | 1,516 |  | 1,007 |  | 4,170 |  | 3,009 |
Canada | 118 |  | 68 |  | 492 |  | 376 |
Europe, Middle East and North Africa | 124 |  | 328 |  | 511 |  | 586 |
Physical contracts meeting the definition of a derivative | $ | 1,758 |  | 1,403 |  | 5,173 |  | 3,971 |

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Revenue from Contracts Outside the Scope of ASC Topic 606 by Product |  |  |  |
Crude oil | $ | 101 |  | 220 |  | 258 |  | 273 |
Natural gas | 1,231 |  | 736 |  | 3,994 |  | 2,650 |
Other | 426 |  | 447 |  | 921 |  | 1,048 |
Physical contracts meeting the definition of a derivative | $ | 1,758 |  | 1,403 |  | 5,173 |  | 3,971 |

Practical Expedients
Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific cases may extend longer, which may be out to the end of field life. We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied as of the end of the reporting period.

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Receivables from Contracts with Customers
At September 30, 2025, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $4,597 million compared with $5,398 million at December 31, 2024, and included both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical natural gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with natural gas sold under contracts for which NPNS has not been elected compared with trade receivables where NPNS has been elected.
Note 17—Earnings Per Share
The following table presents the calculation of net income (loss) available to common shareholders and basic and diluted EPS. For the periods presented in the table below, diluted EPS calculated under the two-class method was more dilutive.

| Millions of Dollars (except per share amounts)
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Basic earnings per share |  |  |  |
Net income (loss) | $ | 1,726 |  | 2,059 | 6,546 | 6,939
Less: Dividends and undistributed earnings |  |  |  |
allocated to participating securities | 6 | 7 | 22 | 21
Net income (loss) available to common shareholders | $ | 1,720 |  | 2,052 | 6,524 | 6,918
Weighted-average common shares outstanding (in millions) | 1,245 | 1,161 | 1,259 | 1,169
Net income (loss) per share of common stock | $ | 1.38 |  | 1.77 | 5.18 | 5.92
Diluted earnings per share |  |  |  |
Net income (loss) available to common shareholders | $ | 1,720 |  | 2,052 | 6,524 | 6,918
Weighted-average common shares outstanding (in millions) | 1,245 | 1,161 | 1,259 | 1,169
Add: Dilutive impact of options and unvested |  |  |  |
non-participating RSU/PSUs (in millions) | 2 | 2 | 1 | 2
Weighted-average diluted shares outstanding (in millions) | 1,247 | 1,163 | 1,260 | 1,171
Net income (loss) per share of common stock | $ | 1.38 |  | 1.76 | 5.18 | 5.91

Note 18—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48 (L48); Canada; Europe, Middle East and North Africa (EMENA); Asia Pacific (AP); and Other International (OI).
Corporate and Other (Corporate) represents income and costs not directly associated with an operating segment, such as most interest expense, premiums on early retirement of debt, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.
Our chief operating decision maker (CODM) is our Chairman of the Board of Directors and Chief Executive Officer, who evaluates performance and allocates resources among our operating segments based on each segment's net income (loss). This is done through the annual budget and forecasting process.
Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

Three Months Ended September 30, 2025 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Segment sales and other operating revenues |  |  |  |  |  |  |  |
Sales and other operating revenues | $ | 1,443 |  | 10,541 |  | 1,414 |  | 1,578 |  | 515 |  | — |  | 24 |  | 15,515 |
Intersegment eliminations | — |  | (3) |  | (473) |  | — |  | — |  | — |  | (8) |  | (484) |
Consolidated sales and other operating revenues | 1,443 |  | 10,538 |  | 941 |  | 1,578 |  | 515 |  | — |  | 16 |  | 15,031 |
Significant segment expenses* |  |  |  |  |  |  |  |
Production and operating expenses | 564 |  | 1,434 |  | 218 |  | 213 |  | 101 |  | — |  | 102 |  | 2,632 |
DD&A | 327 |  | 2,079 |  | 142 |  | 245 |  | 113 |  | — |  | 11 |  | 2,917 |
Income tax provision (benefit) | 61 |  | 345 |  | 60 |  | 676 |  | 89 |  | — |  | (29) |  | 1,202 |
Total | 952 |  | 3,858 |  | 420 |  | 1,134 |  | 303 |  | — |  | 84 |  | 6,751 |
Other segment items |  |  |  |  |  |  |  |
Equity in earnings of affiliates | — |  | (3) |  | — |  | (157) |  | (194) |  | — |  | 9 |  | (345) |
Interest income | — |  | — |  | — |  | — |  | (2) |  | — |  | (60) |  | (62) |
Interest and debt expense | — |  | — |  | — |  | — |  | — |  | — |  | 223 |  | 223 |
Other** | 361 |  | 5,443 |  | 333 |  | 274 |  | 99 |  | (4) |  | 232 |  | 6,738 |
Total | 361 |  | 5,440 |  | 333 |  | 117 |  | (97) |  | (4) |  | 404 |  | 6,554 |
Net income (loss) | $ | 130 |  | 1,240 |  | 188 |  | 327 |  | 309 |  | 4 |  | (472) |  | 1,726 |
*The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: L48, OI and Corporate
Other income and Selling, general and administrative expenses: L48, Canada, EMENA, AP, OI and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Exploration expenses, Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Impairments: L48
Foreign currency transaction (gain) loss: Canada, AP and Corporate
Other expenses: Alaska, L48, EMENA and Corporate

Other Segment Disclosures

Three Months Ended September 30, 2025 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Investment in and advances to affiliates | $ | 3 |  | 127 |  | — |  | 2,163 |  | 4,820 |  | — |  | 1,624 |  | 8,737 |
Total assets | 19,736 |  | 64,387 |  | 9,801 |  | 10,405 |  | 8,052 |  | — |  | 10,091 |  | 122,472 |
Capital expenditures and investments | 753 |  | 1,571 |  | 152 |  | 293 |  | 70 |  | — |  | 27 |  | 2,866 |

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Three Months Ended September 30, 2024 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Segment sales and other operating revenues |  |  |  |  |  |  |  |
Sales and other operating revenues | $ | 1,481 |  | 9,080 |  | 1,139 |  | 1,337 |  | 478 |  | — |  | 16 |  | 13,531 |
Intersegment eliminations | — |  | — |  | (479) |  | — |  | — |  | — |  | (11) |  | (490) |
Consolidated sales and other operating revenues | 1,481 |  | 9,080 |  | 660 |  | 1,337 |  | 478 |  | — |  | 5 |  | 13,041 |
Significant segment expenses* |  |  |  |  |  |  |  |
Production and operating expenses | 520 |  | 1,180 |  | 269 |  | 154 |  | 110 |  | — |  | 28 |  | 2,261 |
DD&A | 309 |  | 1,640 |  | 147 |  | 189 |  | 97 |  | — |  | 8 |  | 2,390 |
Income tax provision (benefit) | 103 |  | 347 |  | 10 |  | 678 |  | 73 |  | — |  | (35) |  | 1,176 |
Total | 932 |  | 3,167 |  | 426 |  | 1,021 |  | 280 |  | — |  | 1 |  | 5,827 |
Other segment items |  |  |  |  |  |  |  |
Equity in earnings of affiliates | 1 |  | — |  | — |  | (154) |  | (290) |  | — |  | 2 |  | (441) |
Interest income | — |  | — |  | — |  | — |  | (2) |  | — |  | (105) |  | (107) |
Interest and debt expense | — |  | — |  | — |  | — |  | — |  | — |  | 189 |  | 189 |
Other** | 281 |  | 4,672 |  | 209 |  | 172 |  | 35 |  | (1) |  | 146 |  | 5,514 |
Total | 282 |  | 4,672 |  | 209 |  | 18 |  | (257) |  | (1) |  | 232 |  | 5,155 |
Net income (loss) | $ | 267 |  | 1,241 |  | 25 |  | 298 |  | 455 |  | 1 |  | (228) |  | 2,059 |
*The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: L48 and OI
Other income: Alaska, L48, Canada, OI and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Selling, general and administrative expenses and Exploration Expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate
Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate
Other expenses: L48, EMENA and Corporate

Other Segment Disclosures

Three Months Ended September 30, 2024 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Investment in and advances to affiliates | $ | 33 |  | 121 |  | — |  | 1,335 |  | 4,993 |  | 7 |  | 1,502 |  | 7,991 |
Total assets | 17,401 |  | 42,346 |  | 10,072 |  | 8,161 |  | 8,323 |  | 6 |  | 10,390 |  | 96,699 |
Capital expenditures and investments | 691 |  | 1,653 |  | 136 |  | 248 |  | 100 |  | — |  | 88 |  | 2,916 |

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Nine Months Ended September 30, 2025 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Segment sales and other operating revenues |  |  |  |  |  |  |  |
Sales and other operating revenues | $ | 4,368 |  | 32,055 |  | 4,280 |  | 4,918 |  | 1,410 |  | — |  | 56 |  | 47,087 |
Intersegment eliminations | — |  | (6) |  | (1,506) |  | — |  | — |  | — |  | (23) |  | (1,535) |
Consolidated sales and other operating revenues | 4,368 |  | 32,049 |  | 2,774 |  | 4,918 |  | 1,410 |  | — |  | 33 |  | 45,552 |
Significant segment expenses* |  |  |  |  |  |  |  |
Production and operating expenses | 1,616 |  | 4,399 |  | 635 |  | 669 |  | 251 |  | — |  | 140 |  | 7,710 |
DD&A | 1,043 |  | 5,986 |  | 416 |  | 662 |  | 350 |  | — |  | 44 |  | 8,501 |
Income tax provision (benefit) | 247 |  | 1,175 |  | 191 |  | 2,191 |  | 220 |  | — |  | (159) |  | 3,865 |
Total | 2,906 |  | 11,560 |  | 1,242 |  | 3,522 |  | 821 |  | — |  | 25 |  | 20,076 |
Other segment items |  |  |  |  |  |  |  |
Equity in earnings of affiliates | — |  | (11) |  | — |  | (445) |  | (585) |  | — |  | (11) |  | (1,052) |
Interest income | — |  | — |  | — |  | — |  | (6) |  | — |  | (199) |  | (205) |
Interest and debt expense | — |  | — |  | — |  | — |  | — |  | — |  | 660 |  | 660 |
Other** | 870 |  | 16,071 |  | 939 |  | 858 |  | 230 |  | (7) |  | 566 |  | 19,527 |
Total | 870 |  | 16,060 |  | 939 |  | 413 |  | (361) |  | (7) |  | 1,016 |  | 18,930 |
Net income (loss) | $ | 592 |  | 4,429 |  | 593 |  | 983 |  | 950 |  | 7 |  | (1,008) |  | 6,546 |
*The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: L48, OI and Corporate
Other income: L48, Canada, EMENA, AP, OI and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Selling, general and administrative expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate
Exploration expenses, Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Impairments: L48 and EMENA
Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate
Other expenses: Alaska, L48, EMENA and Corporate

Other Segment Disclosures

Nine Months Ended September 30, 2025 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Investment in and advances to affiliates | $ | 3 |  | 127 |  | — |  | 2,163 |  | 4,820 |  | — |  | 1,624 |  | 8,737 |
Total assets | 19,736 |  | 64,387 |  | 9,801 |  | 10,405 |  | 8,052 |  | — |  | 10,091 |  | 122,472 |
Capital expenditures and investments | 2,785 |  | 5,089 |  | 461 |  | 923 |  | 188 |  | — |  | 84 |  | 9,530 |

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Nine Months Ended September 30, 2024 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Segment sales and other operating revenues |  |  |  |  |  |  |  |
Sales and other operating revenues | $ | 4,934 |  | 27,442 |  | 4,136 |  | 4,090 |  | 1,495 |  | — |  | 40 |  | 42,137 |
Intersegment eliminations | — |  | (1) |  | (1,599) |  | — |  | — |  | — |  | (28) |  | (1,628) |
Consolidated sales and other operating revenues | 4,934 |  | 27,441 |  | 2,537 |  | 4,090 |  | 1,495 |  | — |  | 12 |  | 40,509 |
Significant segment expenses* |  |  |  |  |  |  |  |
Production and operating expenses | 1,489 |  | 3,420 |  | 709 |  | 471 |  | 281 |  | — |  | 70 |  | 6,440 |
DD&A | 954 |  | 4,629 |  | 471 |  | 544 |  | 314 |  | — |  | 23 |  | 6,935 |
Income tax provision (benefit) | 360 |  | 1,099 |  | 152 |  | 2,121 |  | 173 |  | — |  | (142) |  | 3,763 |
Total | 2,803 |  | 9,148 |  | 1,332 |  | 3,136 |  | 768 |  | — |  | (49) |  | 17,138 |
Other segment items |  |  |  |  |  |  |  |
Equity in earnings of affiliates | 1 |  | — |  | — |  | (431) |  | (840) |  | — |  | 5 |  | (1,265) |
Interest income | — |  | — |  | — |  | — |  | (6) |  | — |  | (301) |  | (307) |
Interest and debt expense | — |  | — |  | — |  | — |  | — |  | — |  | 592 |  | 592 |
Other** | 1,157 |  | 14,412 |  | 739 |  | 532 |  | 162 |  | (3) |  | 413 |  | 17,412 |
Total | 1,158 |  | 14,412 |  | 739 |  | 101 |  | (684) |  | (3) |  | 709 |  | 16,432 |
Net income (Loss) | $ | 973 |  | 3,881 |  | 466 |  | 853 |  | 1,411 |  | 3 |  | (648) |  | 6,939 |
*The significant segment expense categories and amounts in the table above align with segment-level information that is regularly provided to the CODM.
**Other segment items not required to be separately disclosed for each reportable segment include:
Gain (loss) on dispositions: L48 and OI
Other income, Selling, general and administrative expenses and Exploration expenses: Alaska, L48, Canada, EMENA, AP, OI and Corporate
Purchased commodities: Alaska, L48, Canada, EMENA and AP
Impairments: Alaska and L48
Taxes other than income taxes and Accretion on discounted liabilities: Alaska, L48, Canada, EMENA, AP and Corporate
Foreign currency transaction (gain) loss: Canada, EMENA, AP and Corporate
Other expenses: Alaska, L48, EMENA and Corporate

Other Segment Disclosures

Nine Months Ended September 30, 2024 | Millions of Dollars
| Alaska | L48 | Canada | EMENA | AP | OI | Corporate | Consolidated Total
Investment in and advances to affiliates | $ | 33 |  | 121 |  | — |  | 1,335 |  | 4,993 |  | 7 |  | 1,502 |  | 7,991 |
Total assets | 17,401 |  | 42,346 |  | 10,072 |  | 8,161 |  | 8,323 |  | 6 |  | 10,390 |  | 96,699 |
Capital expenditures and investments | 2,102 |  | 4,918 |  | 419 |  | 694 |  | 235 |  | — |  | 433 |  | 8,801 |

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Notes to Consolidated Financial Statements | Table of Contents

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Sales and Other Operating Revenues by Geographic Location* |  |  |
U.S. | $ | 11,887 |  | 10,445 |  | 36,136 |  | 32,201 |
Canada | 798 |  | 660 |  | 2,487 |  | 2,537 |
China | 228 |  | 261 |  | 683 |  | 749 |
Equatorial Guinea | 21 |  | — |  | 377 |  | — |
Libya | 434 |  | 307 |  | 1,350 |  | 1,277 |
Malaysia | 201 |  | 217 |  | 604 |  | 746 |
Norway | 460 |  | 640 |  | 1,494 |  | 1,778 |
Singapore | 327 |  | — |  | 508 |  | — |
U.K. | 673 |  | 510 |  | 1,909 |  | 1,217 |
Other foreign countries | 2 |  | 1 |  | 4 |  | 4 |
Worldwide consolidated | $ | 15,031 |  | 13,041 |  | 45,552 |  | 40,509 |
Sales and Other Operating Revenues by Product |  |  |  |
Crude oil | $ | 10,010 |  | 9,806 |  | 30,371 |  | 29,480 |
Natural gas | 2,020 |  | 1,290 |  | 6,782 |  | 4,346 |
Natural gas liquids | 886 |  | 693 |  | 2,879 |  | 2,035 |
Other** | 2,115 |  | 1,252 |  | 5,520 |  | 4,648 |
Consolidated sales and other operating revenues by product | $ | 15,031 |  | 13,041 |  | 45,552 |  | 40,509 |

*Sales and other operating revenues are attributable to countries based on the location of the selling operation.
**Includes bitumen, power and LNG.

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Notes to Consolidated Financial Statements | Table of Contents

Note 19—Income Taxes
Our effective tax rate for the three-month periods ended September 30, 2025, and September 30, 2024, was 41.0 percent and 36.4 percent, respectively. The change in the effective tax rate for the three-month period ended September 30, 2025, is primarily due to a shift in our mix of income among taxing jurisdictions.
Our effective tax rate for the nine-month periods ended September 30, 2025, and 2024, was 37.1 percent and 35.2 percent, respectively. The change in the effective tax rate for the nine-month period ended September 30, 2025, is primarily due to a shift in our mix of income among taxing jurisdictions partly offset by a change to our valuation allowance in the current year and the recognition of a Malaysia tax benefit occurring in the prior year, both described below.
The relevant provisions of the One Big Beautiful Bill Act (OBBBA), enacted on July 4, 2025, were implemented during the third quarter of 2025. The changes introduced by the legislation did not have a material impact on our effective tax rate for the quarter, and we do not expect a material impact on our effective tax rate for the full year 2025.
During the first quarter of 2025, our valuation allowance decreased $56 million, relating to the expected utilization of previously unrecognized capital loss carryforwards due to our agreement to sell our interests in the Ursa and Europa fields, and the Ursa Oil Pipeline Company LLC to Shell Offshore Inc. and Shell Pipeline Company LP, respectively.
During the first quarter of 2024, we recorded a $76 million tax benefit associated with a deepwater investment tax incentive for Malaysia Blocks J and G.
The company has ongoing income tax audits in a number of jurisdictions. The government agents in charge of these audits regularly request additional time to complete audits, which we generally grant, and conversely, occasionally close audits unpredictably. Within the next twelve months, we may have audit periods close that could significantly impact our total unrecognized tax benefits. The amount of such change is not estimable but could be significant when compared with our total unrecognized tax benefits.
Note 20—New Accounting Standards
In December 2023, the FASB issued ASU No. 2023-09, “Improvements to Income Tax Disclosures” which enhances the disclosure requirements within Topic 740 “Income Taxes.” The enhancements will impact our financial statement disclosures only and will be applied prospectively with retrospective application permitted. The ASU is effective for annual periods beginning after December 15, 2024, and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.
In November 2024, the FASB issued ASU No. 2024-03, “Disaggregation of Income Statement Expenses” to improve the disclosures about a public business entity’s expenses (including purchases of inventory, employee compensation, depreciation, depletion and amortization) in commonly presented expense captions. The ASU will impact our financial statement disclosures only and will be applied prospectively with retrospective application permitted. The ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.

| ConocoPhillips 2025 Q3 10-Q | 32

Management’s Discussion and Analysis | Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 53.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss).
Business Environment and Executive Overview
ConocoPhillips is one of the world’s leading E&P companies based on production and reserves, with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes 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. Headquartered in Houston, Texas, at September 30, 2025, we employed approximately 11,400 people worldwide and had total assets of $122 billion.
Overview
At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, global demand for our products, oil and gas inventory levels, governmental policies, tariffs, inflation and supply chain disruptions.
Throughout 2025, the price of crude oil has been volatile due to multiple macroeconomic and geopolitical forces which slowed global oil demand growth concurrent with higher oil production from OPEC Plus and other major oil producing countries. We continue to closely monitor the macroeconomic environment, including any impacts from tariffs, and the ongoing market volatility in the energy landscape and across global markets for implications to our business, results of operations and financial condition.
As the global energy industry continues to evolve, we remain committed to creating long-term value for our stockholders. We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets. Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.

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Management’s Discussion and Analysis | Table of Contents

In November 2024, we completed our acquisition of Marathon Oil Corporation (Marathon Oil). In the first half of 2025, we completed the asset integration of Marathon Oil and remain on track for more than $1 billion of synergies on a run-rate basis by year-end 2025 and over $1 billion of one-time benefits. These one-time benefits include $0.5 billion recognized previously upon close of the transaction related to the utilization of foreign tax credits, with the remainder consisting of net operating losses expected to be realized in future periods. In August 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026. We expect approximately $0.8 billion to consist of G&A reductions, lease operating cost improvements and opportunities in transportation and processing and approximately $0.2 billion to be achieved through margin expansion. See Note 3.
In conjunction with our acquisition of Marathon Oil, we communicated a disposition proceeds target of $2 billion across the portfolio. In August 2025, we announced an increase to this target for a total of $5 billion by year-end 2026. ConocoPhillips has executed dispositions of over $3 billion in 2025 and is on track to meet its $5 billion disposition target by year-end 2026. On October 1, 2025, the company closed the disposition of Lower 48 assets in the Anadarko Basin for $1.3 billion. Additionally, in the fourth quarter of 2025, the sale of certain noncore assets closed or expect to close for approximately $0.5 billion, subject to customary closing adjustments. See Note 3.
In August 2025, we entered into a 20-year agreement, expected to begin in 2030, to purchase four MTPA of LNG offtake from Phase 2 of the Port Arthur LNG project, further advancing our global LNG portfolio strategy. Additionally, in August 2025, we entered into a 20-year agreement to purchase one MTPA of LNG offtake from the Rio Grande LNG Train 5 facility, expected to begin in 2031, bringing our total committed commercial LNG offtake portfolio to approximately 10 MTPA.
The relevant provisions of the One Big Beautiful Bill Act (OBBBA), enacted on July 4, 2025, were implemented during the third quarter of 2025. While OBBBA did not have a material effect on our effective tax rate for the quarter, the changes introduced by the legislation impacted our current and deferred tax calculations, with approximately $0.4 billion cash tax benefit recognized in the third quarter of 2025 and the remaining approximately $0.1 billion to be recognized in the fourth quarter of 2025.
In November 2025, we declared an increase to our quarterly ordinary dividend from $0.78 per share to $0.84 per share, representing an eight percent increase.
Production was 2,399 MBOED in the third quarter of 2025, an increase of 482 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2025 production increased by 83 MBOED or four percent from the same period a year ago.
Third-quarter 2025 production resulted in $5.9 billion of cash provided by operating activities. We returned over $2.2 billion to shareholders, consisting of $1.3 billion through share repurchases and $1.0 billion through our ordinary dividend. We ended the quarter with cash, cash equivalents, restricted cash and short-term investments totaling $6.6 billion and long-term investments in debt securities of $1.1 billion.
Also in the third quarter of 2025, we re-invested $2.9 billion into the business in the form of capital expenditures and investments, with over half of the expenditures related to flexible, short-cycle unconventional plays in the Lower 48 segment, where our production has access to both domestic and export markets.

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Management’s Discussion and Analysis | Table of Contents

Business Environment
Commodity prices are the most significant factor impacting our profitability and related returns on and of capital to our shareholders. Dynamics that could influence world energy markets and commodity prices include, but are not limited to, global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tariffs, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial, operational and ESG priorities that underpin our value proposition.
Our earnings and operating cash flows generally correlate with price levels for crude oil and natural gas, which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas:
Brent crude oil prices averaged $69.07 per barrel in the third quarter of 2025, a decrease of 14 percent compared with $80.18 per barrel in the third quarter of 2024. WTI at Cushing crude oil prices averaged $64.93 per barrel in the third quarter of 2025, a decrease of 14 percent compared with $75.10 per barrel in the third quarter of 2024. Oil prices were lower in the third quarter of 2025 as global oil supplies increased faster than global oil demand.
U.S. Henry Hub natural gas prices averaged $3.07 per MMBTU in the third quarter of 2025, an increase of 43 percent compared with $2.15 per MMBTU in the third quarter of 2024. U.S. Henry Hub prices improved due to stronger demand and lower inventory levels versus the same time last year. We expect a risk of volatility in regional markers to remain throughout 2025.
Our realized bitumen price averaged $41.58 per barrel in the third quarter of 2025, a decrease of 12 percent compared with $47.32 per barrel in the third quarter of 2024. The decrease in the third quarter of 2025 was driven by falling WTI prices due to concerns over a slowdown in global trade and OPEC Plus increasing production targets, partly offset by strengthened WCS differentials due to additional egress capacity at the Trans Mountain Pipeline Expansion.
For the third quarter of 2025, our total average realized price was $46.44 per BOE, a decrease of 14 percent compared with $54.18 per BOE in the third quarter of 2024.

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Management’s Discussion and Analysis | Table of Contents

Key Operating and Financial Summary
•Reported third-quarter 2025 earnings per share of $1.38;
•Generated cash provided by operating activities of $5.9 billion;
•Raised ordinary dividend by 8% to $0.84 per share;
•Delivered total company and Lower 48 production of 2,399 MBOED and 1,528 MBOED, respectively;
•Exceeded $3 billion in dispositions in 2025 and on track to meet $5 billion disposition target by year-end 2026;
•Advanced commercial LNG strategy by signing 20-year sales and purchase agreements at PALNG Phase 2 and Rio Grande LNG Train 5, expected to commence in 2030 and 2031, respectively;
•Distributed over $2.2 billion to shareholders, including $1.3 billion through share repurchases and $1.0 billion through the ordinary dividend; and
•Ended the quarter with cash, cash equivalents, restricted cash and short-term investments of $6.6 billion and long-term investments of $1.1 billion.
Outlook
Production
Fourth-quarter 2025 production is expected to be 2.30 to 2.34 MMBOED.
Full-year production guidance has been raised to 2.375 MMBOED, compared to prior guidance of 2.35 to 2.37 MMBOED.
All other guidance remains unchanged. Guidance includes the impact from closed dispositions.

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Results of Operations | Table of Contents

Results of Operations
Unless otherwise indicated, discussion of consolidated results for the three- and nine-month periods ended September 30, 2025, is based on a comparison with the corresponding period of 2024.
Consolidated Results
Summary Operating Statistics

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Average Net Production |  |  |  |
Crude oil (MBD) |  |  |  |
Consolidated operations | 1,133 |  | 945 |  | 1,144 |  | 938 |
Equity affiliates | 13 |  | 12 |  | 12 |  | 14 |
Total crude oil | 1,146 |  | 957 |  | 1,156 |  | 952 |
Natural gas liquids (MBD) |  |  |  |
Consolidated operations | 428 |  | 302 |  | 413 |  | 287 |
Equity affiliates | 8 |  | 8 |  | 7 |  | 8 |
Total natural gas liquids | 436 |  | 310 |  | 420 |  | 295 |
Bitumen (MBD) | 123 |  | 87 |  | 137 |  | 116 |
Natural gas (MMCFD) |  |  |  |
Consolidated operations | 2,941 |  | 2,149 |  | 2,879 |  | 2,102 |
Equity affiliates | 1,226 |  | 1,232 |  | 1,202 |  | 1,249 |
Total natural gas | 4,167 |  | 3,381 |  | 4,081 |  | 3,351 |
Total Production (MBOED) | 2,399 |  | 1,917 |  | 2,393 |  | 1,921 |
Total Production (MMBOE) | 221 |  | 176 |  | 653 |  | 526 |

| Dollars Per Unit
Average Sales Prices |  |  |  |
Crude oil (per BBL) |  |  |  |
Consolidated operations | $ | 66.12 |  | 76.78 |  | 67.31 |  | 78.90 |
Equity affiliates | 67.56 |  | 76.11 |  | 69.85 |  | 77.72 |
Total crude oil | 66.13 |  | 76.77 |  | 67.34 |  | 78.88 |
Natural gas liquids (per BBL) |  |  |  |
Consolidated operations | 18.71 |  | 21.16 |  | 21.24 |  | 22.07 |
Equity affiliates | 44.39 |  | 49.91 |  | 48.42 |  | 50.64 |
Total natural gas liquids | 19.20 |  | 21.93 |  | 21.74 |  | 22.88 |
Bitumen (per BBL) | 41.58 |  | 47.32 |  | 42.07 |  | 48.89 |
Natural gas (per MCF) |  |  |  |
Consolidated operations | 3.11 |  | 1.99 |  | 3.61 |  | 2.25 |
Equity affiliates | 7.00 |  | 8.41 |  | 7.16 |  | 8.19 |
Total natural gas | $ | 4.28 |  | 4.42 |  | 4.69 |  | 4.53 |

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Results of Operations | Table of Contents

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Exploration Expenses |  |  |  |
General administrative, geological and geophysical, lease rental and other | $ | 51 |  | 70 |  | 164 |  | 236 |
Leasehold impairment | 20 |  | — |  | 56 |  | 4 |
Dry hole | — |  | — |  | 49 |  | 44 |
| $ | 71 |  | 70 |  | 269 |  | 284 |

Total Company Production
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. In the quarter ended September 30, 2025, our operations were producing in the U.S., Australia, Canada, China, Equatorial Guinea, Libya, Malaysia, Norway and Qatar.
Total production in the third quarter of 2025 was 2,399 MBOED, an increase of 482 MBOED or 25 percent from the same period a year ago. Total production in the nine-month period of 2025 was 2,393 MBOED, an increase of 472 MBOED or 25 percent from the same period a year ago. Production increases include:
•New wells online in the Lower 48, Alaska, Australia, Canada, China, Libya, Malaysia and Norway.
•Our acquisition of Marathon Oil, which closed in November 2024. See Note 3.
Production increases were partly offset by normal field decline.
After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2025 production increased by 83 MBOED or four percent from the same period a year ago. After adjusting for closed acquisitions and dispositions, production in the nine-month period of 2025 increased 92 MBOED or four percent from the same period a year ago.

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Results of Operations | Table of Contents

Income Statement Analysis
Unless otherwise indicated, all results in Income Statement Analysis are before-tax.
Below is select financial data provided on a consolidated basis. The full Income Statement can be found in Item 1. Financial Statements.

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Sales and other operating revenues | $ | 15,031 |  | 13,041 |  | 45,552 |  | 40,509 |
Purchased commodities | 5,857 |  | 4,747 |  | 17,130 |  | 14,939 |
Production and operating expenses | 2,632 |  | 2,261 |  | 7,710 |  | 6,440 |
Depreciation, depletion and amortization | 2,917 |  | 2,390 |  | 8,501 |  | 6,935 |
Taxes other than income taxes | 525 |  | 476 |  | 1,648 |  | 1,567 |

Sales and other operating revenues for the three- and nine-month periods of 2025 increased $1,990 million and $5,043 million, respectively. Increases in the third quarter were due to higher volumes of $1,875 million, inclusive of sales volumes from our acquisition of Marathon Oil; higher realized natural gas prices of $303 million and timing of sales as compared to the prior period. These increases were partly offset by lower crude, bitumen and NGL realized prices of $1,273 million. Increases in the nine-month period of 2025 were due to higher volumes of $5,863 million, inclusive of sales volumes from our acquisition of Marathon Oil; timing of sales as compared to the prior period and higher realized natural gas prices of $1,069 million. These increases were partly offset by lower crude, bitumen and NGL realized prices of $3,968 million. See Note 3.
Purchased commodities for the three- and nine-month periods of 2025 increased $1,110 million and $2,191 million, respectively. These increases were due to higher volumes associated with our acquisition of Marathon Oil, higher natural gas prices and higher crude and natural gas volumes, partly offset by lower crude prices. See Note 3.
Production and operating expenses for the three- and nine-month periods of 2025 increased $371 million and $1,270 million, respectively, primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024. See Note 3.
DD&A for the three- and nine-month periods of 2025 increased $527 million and $1,566 million, respectively, primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024. See Note 3.

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Results of Operations | Table of Contents

Segment Results
Unless otherwise indicated, discussion of segment results for the three- and nine-month periods ended September 30, 2025, is based on a comparison with the corresponding period of 2024 and are shown after-tax.
A summary of the company's net income (loss) by business segment follows:

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Alaska | $ | 130 |  | 267 |  | 592 |  | 973 |
Lower 48 | 1,240 |  | 1,241 |  | 4,429 |  | 3,881 |
Canada | 188 |  | 25 |  | 593 |  | 466 |
Europe, Middle East and North Africa | 327 |  | 298 |  | 983 |  | 853 |
Asia Pacific | 309 |  | 455 |  | 950 |  | 1,411 |
Other International | 4 |  | 1 |  | 7 |  | 3 |
Corporate and Other | (472) |  | (228) |  | (1,008) |  | (648) |
Net income (loss) | $ | 1,726 |  | 2,059 |  | 6,546 |  | 6,939 |

For further discussion of segment results, see the following pages.

| ConocoPhillips 2025 Q3 10-Q | 40

Results of Operations | Table of Contents

Alaska

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Select financial data by segment before-tax ($MM)
Sales and other operating revenues | $ | 1,443 |  | 1,481 |  | 4,368 |  | 4,934 |
Production and operating expenses | 564 |  | 520 |  | 1,616 |  | 1,489 |
Depreciation, depletion and amortization | 327 |  | 309 |  | 1,043 |  | 954 |
Taxes other than income taxes | 126 |  | 98 |  | 314 |  | 362 |
Net income (loss) ($MM) | $ | 130 |  | 267 |  | 592 |  | 973 |
Average Net Production |  |  |  |
Crude oil (MBD) | 164 |  | 162 |  | 177 |  | 171 |
Natural gas liquids (MBD) | 12 |  | 14 |  | 14 |  | 14 |
Natural gas (MMCFD) | 36 |  | 37 |  | 44 |  | 38 |
Total Production (MBOED) | 182 |  | 182 |  | 198 |  | 191 |
Total Production (MMBOE) | 17 |  | 17 |  | 54 |  | 52 |
Average Sales Prices |  |  |  |
Crude oil ($ per BBL) | $ | 72.72 |  | 81.32 |  | 73.50 |  | 83.89 |
Natural gas ($ per MCF) | 3.86 |  | 3.98 |  | 3.85 |  | 3.97 |

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2025, Alaska contributed 11 percent of our consolidated liquids production and two percent of our consolidated natural gas production.
Net Income (Loss)
Alaska reported earnings of $130 million and $592 million in the three- and nine-month periods of 2025, respectively, compared with earnings of $267 million and $973 million in the three- and nine-month periods of 2024, respectively.
Earnings in the third quarter of 2025 included lower sales revenues resulting from lower realized prices of $95 million. Decreases to earnings also included higher production and operating expenses of $30 million, driven by a severance accrual related to certain announced cost reduction initiatives. See Note 15.
Earnings in the nine-month period of 2025 included lower sales revenues resulting from lower realized prices of $383 million, partly offset by higher produced volumes of $90 million. Earnings decreases in the nine-month period of 2025 also included higher production and operating expenses of $90 million, driven by higher lease operating expenses and well work activity and a severance accrual related to certain announced cost reduction initiatives, and higher DD&A of $63 million, primarily driven by higher rates and higher production. See Note 15. Increases to earnings included lower taxes other than income taxes of $34 million driven by an impact from the settlement of a contingent matter.
Production
Average production remained flat in the three-month period and increased seven MBOED in the nine-month period of 2025, compared to the respective periods in 2024. Increases to production were primarily due to new wells online and less downtime.
The production increases were partly offset by normal field decline.

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Results of Operations | Table of Contents

Lower 48

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Select financial data by segment before-tax ($MM)
Sales and other operating revenues | $ | 10,538 |  | 9,080 |  | 32,049 |  | 27,441 |
Production and operating expenses | 1,434 |  | 1,180 |  | 4,399 |  | 3,420 |
Depreciation, depletion and amortization | 2,079 |  | 1,640 |  | 5,986 |  | 4,629 |
Taxes other than income taxes | 353 |  | 324 |  | 1,178 |  | 1,014 |
Net income (loss) ($MM) | $ | 1,240 |  | 1,241 |  | 4,429 |  | 3,881 |
Average Net Production |  |  |  |
Crude oil (MBD) | 761 |  | 603 |  | 759 |  | 577 |
Natural gas liquids (MBD) | 401 |  | 278 |  | 385 |  | 263 |
Natural gas (MMCFD) | 2,198 |  | 1,596 |  | 2,142 |  | 1,557 |
Total Production (MBOED) | 1,528 |  | 1,147 |  | 1,501 |  | 1,099 |
Total Production (MMBOE) | 141 |  | 106 |  | 410 |  | 301 |
Average Sales Prices |  |  |  |
Crude oil ($ per BBL) | $ | 63.71 |  | 74.73 |  | 64.96 |  | 76.29 |
Natural gas liquids ($ per BBL) | 18.81 |  | 20.64 |  | 21.26 |  | 21.58 |
Natural gas ($ per MCF) | 1.62 |  | 0.18 |  | 1.95 |  | 0.67 |

The Lower 48 segment consists of operations located in the U.S. Lower 48 states and commercial operations. As of September 30, 2025, the Lower 48 contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.
Net Income (Loss)
Lower 48 reported earnings of $1,240 million and $4,429 million in the three- and nine-month periods of 2025, respectively, compared with earnings of $1,241 million and $3,881 million in the three- and nine-month periods of 2024, respectively.
Earnings in the third quarter of 2025 included higher sales revenues resulting from higher volumes of $1,041 million, which included volumes from our acquisition of Marathon Oil. These increases were partly offset by lower overall realized prices of $429 million, driven by lower crude prices. Decreases to earnings in the third quarter of 2025 included higher DD&A of $344 million and higher production and operating expenses of $199 million, primarily from our acquisition of Marathon Oil. See Note 3.
Earnings in the nine-month period of 2025 included higher sales revenues resulting from higher volumes of $3,607 million which included volumes from our acquisition of Marathon Oil. Additional increases to revenues included a gain of $242 million primarily associated with the divestiture of the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC. These increases were partly offset by lower overall realized prices of $1,290 million, driven by lower crude prices. Additional decreases to earnings in the nine-month period of 2025 included higher DD&A of $1,072 million and higher production and operating expenses of $773 million, primarily from our acquisition of Marathon Oil. See Note 3.
Production
Average production increased 381 MBOED and 402 MBOED in the three- and nine-month periods of 2025, respectively, compared to the respective periods in 2024. Increases to production were primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Midland Basin and Bakken. Production also increased due to our acquisition of Marathon Oil in November 2024. See Note 3.
Production increases were partly offset by normal field decline.

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Results of Operations | Table of Contents

Asset Dispositions, Assets Held for Sale and Planned Dispositions
On October 1, 2025, we closed the disposition of Anadarko Basin assets for $1.3 billion. Including Anadarko Basin, we have completed divestitures of assets totaling approximately $2.6 billion in proceeds. Production from these assets averaged approximately 33MBOED in 2024. See Note 3.
Additionally, in the fourth quarter of 2025, we closed or expect to close dispositions of certain noncore assets for approximately $0.5 billion, subject to customary closing adjustments. See Note 3.

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Results of Operations | Table of Contents

Canada

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Select financial data by segment before-tax ($MM)
Sales and other operating revenues | $ | 941 |  | 660 |  | 2,774 |  | 2,537 |
Production and operating expenses | 218 |  | 269 |  | 635 |  | 709 |
Depreciation, depletion and amortization | 142 |  | 147 |  | 416 |  | 471 |
Taxes other than income taxes | 7 |  | 6 |  | 21 |  | 25 |
Net income (loss) ($MM) | $ | 188 |  | 25 |  | 593 |  | 466 |
Average Net Production |  |  |  |
Crude oil (MBD) | 17 |  | 15 |  | 18 |  | 17 |
Natural gas liquids (MBD) | 7 |  | 7 |  | 6 |  | 6 |
Bitumen (MBD) | 123 |  | 87 |  | 137 |  | 116 |
Natural gas (MMCFD) | 134 |  | 121 |  | 123 |  | 114 |
Total Production (MBOED) | 169 |  | 129 |  | 182 |  | 158 |
Total Production (MMBOE) | 16 |  | 12 |  | 50 |  | 43 |
Average Sales Prices |  |  |  |
Crude oil ($ per BBL) | $ | 55.80 |  | 61.99 |  | 57.73 |  | 65.09 |
Natural gas liquids ($ per BBL) | 20.98 |  | 28.11 |  | 23.09 |  | 30.13 |
Bitumen ($ per BBL) | 41.58 |  | 47.32 |  | 42.07 |  | 48.89 |
Natural gas ($ per MCF)* | 0.37 |  | 0.10 |  | 0.78 |  | 0.46 |

*Average sales prices include unutilized transportation costs.
The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. As of September 30, 2025, Canada contributed 10 percent of our consolidated liquids production and four percent of our consolidated natural gas production.
Net Income (Loss)
Canada reported earnings of $188 million and $593 million in the three- and nine-month periods of 2025, respectively, compared with earnings of $25 million and $466 million in the three- and nine-month periods of 2024, respectively.
Earnings in the third quarter of 2025 included higher sales revenues resulting from higher volumes of $128 million, partly offset by lower realized prices of $58 million. Increases to earnings include lower production and operating expenses of $39 million primarily due to the absence of prior-year planned turnaround activity at Surmont.
Earnings in the nine-month period of 2025 included higher sales revenues resulting from higher volumes of $221 million and timing of sales, offset by lower realized prices of $221 million. Additional increases to earnings include lower production and operating expenses of $56 million primarily due to the absence of prior-year planned turnaround activity at Surmont and lower DD&A of $42 million driven by year-end upward reserve revisions.
Production
Average production increased 40 MBOED and 24 MBOED in the three- and nine-month periods of 2025, respectively. Increases to production resulted from new wells online in the Montney and Surmont and the absence of prior-year planned turnaround activity at Surmont.
Production increases were partly offset by normal field decline.

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Europe, Middle East and North Africa

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Select financial data by segment before-tax ($MM)
Sales and other operating revenues | $ | 1,578 |  | 1,337 |  | 4,918 |  | 4,090 |
Production and operating expenses | 213 |  | 154 |  | 669 |  | 471 |
Depreciation, depletion and amortization | 245 |  | 189 |  | 662 |  | 544 |
Taxes other than income taxes | 11 |  | 10 |  | 33 |  | 31 |
Net income (loss) ($MM) | $ | 327 |  | 298 |  | 983 |  | 853 |
Consolidated Operations |  |  |  |
Average Net Production |  |  |  |
Crude oil (MBD) | 134 |  | 110 |  | 130 |  | 115 |
Natural gas liquids (MBD) | 8 |  | 3 |  | 8 |  | 4 |
Natural gas (MMCFD) | 506 |  | 351 |  | 508 |  | 346 |
Total Production (MBOED) | 227 |  | 171 |  | 223 |  | 177 |
Total Production (MMBOE) | 21 |  | 16 |  | 61 |  | 48 |
Average Sales Prices |  |  |  |
Crude oil ($ per BBL) | $ | 69.46 |  | 80.88 |  | 70.76 |  | 83.45 |
Natural gas liquids ($ per BBL) | 10.09 |  | 46.08 |  | 19.13 |  | 44.81 |
Natural gas ($ per MCF) | 10.31 |  | 10.76 |  | 11.35 |  | 9.71 |

Production and sales prices exclude equity affiliates. See Summary Operating Statistics for equity affiliate totals.
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea and the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. As of September 30, 2025, our Europe, Middle East and North Africa operations contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.
Net Income (Loss)
Europe, Middle East and North Africa reported earnings of $327 million and $983 million in the three- and nine-month periods of 2025, respectively, compared with earnings of $298 million and $853 million in the three- and nine-month periods of 2024, respectively.
Earnings in the third quarter of 2025 included higher revenues inclusive of higher volumes of $115 million, which included volumes added from our acquisition of Marathon Oil, partly offset by lower realized prices of $61 million impacted by lower crude prices. Decreases to earnings in the third quarter included higher production and operating expenses of $19 million and higher DD&A of $18 million, primarily from our acquisition of Marathon Oil. See Note 3.
Earnings in the nine-month period of 2025 included higher revenues resulting from higher volumes of $250 million, which included volumes from our acquisition of Marathon Oil and timing of sales compared to the prior period, offset by lower overall realized prices of $86 million, driven by lower crude prices. Decreases to earnings in the nine-month period included higher production and operating expenses of $61 million and higher DD&A of $37 million, primarily from our acquisition of Marathon Oil. See Note 3.
Consolidated Production
Average consolidated production increased 56 MBOED and 46 MBOED in the three- and nine-month periods of 2025, respectively, compared to the respective periods in 2024. Increases to production were due to the impact from assets acquired from Marathon Oil as well as new wells online in Norway and Libya. See Note 3.
Production increases were partly offset by normal field decline.

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Results of Operations | Table of Contents

Asia Pacific

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Select financial data by segment before-tax ($MM)
Sales and other operating revenues | $ | 515 |  | 478 |  | 1,410 |  | 1,495 |
Production and operating expenses | 101 |  | 110 |  | 251 |  | 281 |
Depreciation, depletion and amortization | 113 |  | 97 |  | 350 |  | 314 |
Taxes other than income taxes | 15 |  | 25 |  | 47 |  | 90 |
Net income (loss) ($MM) | $ | 309 |  | 455 |  | 950 |  | 1,411 |
Consolidated Operations |  |  |  |
Average Net Production |  |  |  |
Crude oil (MBD) | 57 |  | 55 |  | 60 |  | 58 |
Natural gas (MMCFD) | 67 |  | 44 |  | 62 |  | 47 |
Total Production (MBOED) | 68 |  | 62 |  | 70 |  | 66 |
Total Production (MMBOE) | 6 |  | 6 |  | 19 |  | 18 |
Average Sales Prices |  |  |  |
Crude oil ($ per BBL) | $ | 71.72 |  | 80.84 |  | 72.51 |  | 84.15 |
Natural gas ($ per MCF) | 3.60 |  | 3.62 |  | 3.66 |  | 3.75 |

Production and sales prices exclude equity affiliates. See Summary Operating Statistics for equity affiliate totals.
The Asia Pacific segment has operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. As of September 30, 2025, Asia Pacific contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.
Net Income (Loss)
Asia Pacific reported earnings of $309 million and $950 million for the three- and nine-month periods of 2025, respectively, compared with earnings of $455 million and $1,411 million in the three- and nine-month periods of 2024, respectively.
Earnings in the third quarter of 2025 included lower earnings from equity affiliates of $76 million, primarily due to lower LNG sales prices.
Earnings in the nine-month period of 2025 included lower revenues resulting from lower realized prices of $156 million, partly offset by higher volumes of $46 million, the absence of a $76 million tax benefit associated with a deepwater investment tax incentive for Malaysia blocks J and G and higher exploration expenses of $37 million driven primarily by dry hole expenses associated with certain suspended wells. Additional decreases to earnings included lower earnings from equity affiliates of $208 million, primarily due to lower LNG sales prices. See Note 6 and Note 19.
Consolidated Production
Average consolidated production increased six MBOED and four MBOED in the three- and nine-month periods of 2025, respectively, compared to the respective periods in 2024. Increases to production were primarily due to development activity in Bohai Bay in China and Gumusut in Malaysia.
Production increases were partly offset by normal field decline.

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Results of Operations | Table of Contents

Other International

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Net income (loss) ($MM) | $ | 4 |  | 1 |  | 7 |  | 3 |

The Other International segment consists of activities associated with prior operations in other countries.
Corporate and Other

| Millions of Dollars
| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 | 2024 | 2025 | 2024
Net income (loss) |  |  |  |
Net interest expense | $ | (152) |  | (79) |  | (402) |  | (261) |
Corporate G&A expenses | (163) |  | (99) |  | (420) |  | (282) |
Technology | (88) |  | (32) |  | (128) |  | (100) |
Other income (expense) | (69) |  | (18) |  | (58) |  | (5) |
| $ | (472) |  | (228) |  | (1,008) |  | (648) |

Net interest expense consists of interest and debt expense, net of interest income and capitalized interest. Net interest expense was impaired in the three- and nine-month periods of 2025 due to higher interest expense driven by our acquisition of Marathon Oil. See Note 3.
Corporate G&A expenses include compensation programs and staff costs. Corporate G&A expenses increased in the three- and nine-month periods of 2025, primarily due to transaction and integration expenses associated with our acquisition of Marathon Oil and a severance accrual related to certain announced cost reduction initiatives. See Note 3 and Note 15.
Technology includes our investments in low-carbon and other new technologies or businesses and licensing revenues. Other new technologies or businesses and licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery, as well as LNG.
Other income (expense) includes certain consolidating tax-related items, foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on the early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Other income (expense) was impaired in the third quarter of 2025 primarily due to a consolidating tax adjustment.

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Capital Resources and Liquidity | Table of Contents

Capital Resources and Liquidity
Financial Indicators

| Millions of Dollars
| September 30 2025 | December 31 2024
Cash and cash equivalents | $ | 5,260 |  | 5,607 |
Short-term investments | 996 |  | 507 |
Total debt | 23,482 |  | 24,324 |
Total equity | 64,923 |  | 64,796 |
Percent of total debt to capital* | 27 | % | 27 |
Percent of floating-rate debt to total debt | 1 | % | 1 |

*Capital includes total debt and total equity.
To meet our short-term and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. During the first nine months of 2025, the primary uses of our available cash were $9.5 billion to support our ongoing capital expenditures and investments program, $4.0 billion to repurchase common stock, $3.0 billion to pay the ordinary dividend and $0.9 billion to retire debt at maturity, partly offset by proceeds from noncore asset sales of $1.6 billion.
At September 30, 2025, we had total liquidity of $11.8 billion, comprised of cash and cash equivalents of $5.3 billion, short-term investments of $1.0 billion and available borrowing capacity under our credit facility of $5.5 billion. In addition, we have $1.1 billion of long-term investments in debt securities. We believe current cash balances and cash generated by operating activities, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, acquisitions, dividend payments and debt obligations.
Significant Changes in Capital
Operating Activities
Cash provided by operating activities totaled $15.5 billion for the first nine months of 2025 compared with $15.7 billion for the corresponding period of 2024. The decrease resulted from lower commodity prices and tax payment timing, mostly offset by operations from the 2024 Marathon acquisition.
Our short-term and long-term operating cash flows are highly dependent on the prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile, driven by market conditions beyond our control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.
The level of absolute production volumes, as well as the product and location mix, is another significant factor impacting our cash flows. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; government regulations; impacts of a global pandemic; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices.
To maintain or grow our production volumes, we must continue adding to our proved reserve base. See the “Capital Expenditures and Investments” section.

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Investing Activities
For the first nine months of 2025, we invested $9.5 billion in capital expenditures and investments. Our 2025 operating plan capital expenditures are currently expected to be $12.3 billion to $12.6 billion. Our 2024 capital expenditures and investments were $12.1 billion. See the “Capital Expenditures and Investments” section.
In the first nine months of 2025, net cash used in investing activities was impacted by an increase in working capital changes associated with investing activities of $488 million, due to timing of invoice payments.
Proceeds from asset sales were $1.6 billion in the first nine months of 2025 compared with $0.2 billion for the corresponding period in 2024. We received proceeds of approximately $1.5 billion from the sale of assets in our Lower 48 segment and $0.1 billion from real estate asset sales in our Corporate segment. See Note 3.
In July 2025, we signed an agreement to divest Lower 48 assets in the Anadarko Basin. The $1.3 billion transaction closed on October 1, 2025. See Note 3.
In the fourth quarter of 2025, we closed or expect to close dispositions of certain noncore Lower 48 assets for approximately $0.5 billion, subject to customary closing adjustments. S ee Note 3.
We invest in short-term and long-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity, and provide yield and total returns. These investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Short-term funds needed to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities of less than one year. Funds we consider available to maintain resiliency in longer-term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities of greater than one year. See Note 10.
Investing activities in the first nine months of 2025 included net purchases of $556 million of investments. We had net purchases of $94 million of short-term investments and net purchases of $462 million of long-term investments. See Note 13.
Financing Activities
In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030. The credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million or as support for our commercial paper program. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at September 30, 2025.
Our debt balance at September 30, 2025, was $23.5 billion compared with $24.3 billion at December 31, 2024. The current portion of debt, including future payments for finance leases, is $1.0 billion at September 30, 2025. In the second quarter of 2025, the company retired $0.2 billion principal amount of our 3.35% Notes at maturity. In the first quarter of 2025, the company retired $0.5 billion principal amount of debt at maturity, consisting of $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures. Debt payments are expected to be made using current cash balances and cash provided by operating activities.
The current long-term debt credit ratings are:
•Fitch: “A” with a “stable” outlook
•S&P: “A-” with a “stable” outlook
•Moody's: “A2” with a "stable" outlook
See Note 5 for additional information on debt and the revolving credit facility.
Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At September 30, 2025, and December 31, 2024, we had direct bank letters of credit of $243 million and $278 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

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Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and sell an indeterminate number of various types of debt and equity securities.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section.
We believe in delivering value to our shareholders through our return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and through-cycle share repurchases. We anticipate returning greater than 30 percent of cash from operating activities through cycles.
In the first nine months of 2025, we paid ordinary dividends of $2.34 per share and in the first nine months of 2024, we paid ordinary dividends of $1.74 per share and VROC payments of $0.60 per share.
In November 2025, we declared an increase to our quarterly ordinary dividend from $0.78 per share to $0.84 per share, representing an eight percent increase. The dividend is payable December 1, 2025, to shareholders of record at the close of business on November 17, 2025.
In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our prior authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate purchases. Share repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. As of September 30, 2025, share repurchases since the inception of our current program totaled 474.8 million shares and $38.3 billion. In the nine months ended September 30, 2025, we repurchased 42.2 million shares for a cost of $4.0 billion.
See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2024 Annual Report on Form 10-K.
Capital Expenditures and Investments

| Millions of Dollars
| Nine Months Ended September 30
| 2025 | 2024
Alaska | $ | 2,785 |  | 2,102 |
Lower 48 | 5,089 |  | 4,918 |
Canada | 461 |  | 419 |
Europe, Middle East and North Africa | 923 |  | 694 |
Asia Pacific | 188 |  | 235 |
Corporate and Other | 84 |  | 433 |
Capital expenditures and investments | $ | 9,530 |  | 8,801 |

During the first nine months of 2025, capital expenditures and investments supported key operating activities and acquisitions, primarily:
•Appraisal and development activities in Alaska related to the Western North Slope, inclusive of Willow, and development activities in the Greater Kuparuk Area.
•Development activities in the Lower 48, primarily in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.
•Appraisal and development activities in the Montney as well as development and optimization of Surmont in Canada.
•Development and appraisal activities across assets in Norway and development activities in Libya.
•Continued development activities in China.
•Investments in our global LNG operations.
Our 2025 operating plan capital expenditure guidance is currently expected to be $12.3 billion to $12.6 billion. Our operating plan capital was $12.1 billion in 2024.

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Guarantor Summarized Financial Information
We have various cross guarantees among our Obligor Group: ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC, with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.
The following tables present summarized financial information for the Obligor Group, as defined below:
•The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.
•Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information.
•Non-Obligated Subsidiaries are excluded from the presentation.
Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented below:
Summarized Income Statement Data

| Millions of Dollars
| Nine Months Ended September 30, 2025
Revenues and Other Income | $ | 29,287 |
Income (loss) before income taxes* | 6,092 |
Net income (loss) | 6,546 |

*Includes approximately $8.3 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.
Summarized Balance Sheet Data

| Millions of Dollars
| September 30 2025 | December 31 2024
Current Assets | $ | 6,086 |  | 6,077 |
Amounts due from Non-Obligated Subsidiaries, current | 894 |  | 319 |
Noncurrent Assets | 127,862 |  | 120,845 |
Amounts due from Non-Obligated Subsidiaries, noncurrent | 11,939 |  | 11,719 |
Current Liabilities | 4,269 |  | 4,504 |
Amounts due to Non-Obligated Subsidiaries, current | 872 |  | 935 |
Noncurrent Liabilities | 71,222 |  | 64,088 |
Amounts due to Non-Obligated Subsidiaries, noncurrent | 48,774 |  | 41,826 |

Contingencies
We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 9.
For more discussion of the below topics, please see the "Contingencies" section in Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2024 Annual Report on Form 10-K.

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Legal and Tax Matters
We are subject to various lawsuits and claims, including, but not limited to, matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations and climate change. We will continue to defend ourselves vigorously in these matters.
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. We occasionally receive requests for information or notices of potential liability from the U.S. EPA and state environmental agencies alleging that we are a potentially responsible party under the CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of September 30, 2025, there were 16 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws. For remediation activities in the U.S. and Canada, our consolidated balance sheet included total accrued environmental costs of $210 million at September 30, 2025, compared with $206 million at December 31, 2024. We expect to incur a substantial amount of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.
Climate Change
Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on GHG emissions reduction. These laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition.
Company Response to Climate-Related Risks
The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, emissions reduction technologies, alternative energy technologies and changes in consumer trends. The strategy guides our choices around portfolio composition, emissions reductions, targets, incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.
Our Climate Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our operational emissions-reduction targets. First, meeting global energy demand requires a focus on delivering production that will best compete in any energy demand scenario. This production will be delivered from resources with a competitive cost of supply and low GHG intensity, as well as portfolio diversity by market and asset type. Next, our focus is on delivering superior returns through the cycles based on our foundational principles of balance sheet strength, peer-leading distributions and disciplined investments. Finally, to drive accountability for the emissions that are within our ownership, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.

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| Table of Contents

Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, the anticipated benefits of our acquisition of Marathon Oil, the anticipated impact of our acquisition of Marathon Oil on the combined company’s business and future financial and operating results and the expected amount and timing of synergies from our acquisition of Marathon Oil are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures and discussions concerning development or replacement of reserves and future dividends. You can often identify our forward-looking statements by the words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.
We based our forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect or inaccurate, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:
•Effects of volatile commodity prices, including prolonged periods of low commodity prices, which may adversely impact our operating results and our ability to execute on our strategy and could result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.
•Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict; security threats on facilities and infrastructure; global health crises; the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries; or the resulting company or third-party actions in response to such changes.
•The potential for insufficient liquidity or other factors, such as those described herein, that could impact our ability to repurchase shares and declare and pay dividends, whether fixed or variable.
•Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.
•Reductions in our reserve replacement rates, whether as a result of significant declines in commodity prices or otherwise.
•Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
•Failure to progress or complete announced and future development plans related to constructing, modifying or operating E&P and LNG facilities, or unexpected changes in costs, inflationary pressures or technical equipment related to such plans.
•Significant operational or investment changes imposed by legislative and regulatory initiatives and international agreements addressing environmental concerns, including initiatives addressing the impact of global climate change, such as limiting or reducing GHG emissions; regulations concerning hydraulic fracturing, methane emissions, flaring or water disposal; and prohibitions on commodity exports.
•Broader societal attention to and efforts to address climate change may cause substantial investment in and increased adoption of competing or alternative energy sources.
•Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate Risk Strategy.
•Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.
•Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.

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•Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events; war; terrorism; cybersecurity threats or information technology failures, constraints or disruptions.
•Liability for remedial actions, including removal and reclamation obligations, under existing or future environmental regulations and litigation.
•Liability resulting from pending or future litigation or our failure to comply with applicable laws and regulations.
•General domestic and international economic, political and diplomatic developments, including deterioration of international trade relationships; the imposition of trade restrictions or tariffs relating to commodities and material or products (such as aluminum and steel) used in the operation of our business; expropriation of assets; changes in governmental policies relating to commodity pricing, including the imposition of price caps; sanctions; or other adverse regulations or taxation policies.
•Competition and consolidation in the oil and gas E&P industry, including competition for sources of supply, services, personnel and equipment.
•Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment.
•Challenges or delays to our execution of, or successful implementation of the acquisition of Marathon Oil or any future asset dispositions or acquisitions we elect to pursue; potential disruption of our operations, including the diversion of management time and attention; our inability to realize anticipated cost savings or capital expenditure reductions; difficulties integrating acquired businesses and technologies; or other unanticipated changes.
•Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we anticipate, if at all.
•The operation, financing and management of risks of our joint ventures.
•The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.
•Uncertainty as to the long-term value of our common stock.
•The factors generally described in Part I—Item 1A in our 2024 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about market risks for the nine months ended September 30, 2025, does not differ materially from that discussed under Item 7A in our 2024 Annual Report on Form 10-K.
Item 4. Controls and Procedures
We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. At September 30, 2025, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively at September 30, 2025.
In the first quarter of 2025, we completed the final phase of a multi-year implementation of an updated global enterprise resource planning system (ERP). As a result, we made corresponding changes to our business processes and information systems, updating applicable internal controls over financial reporting where necessary.
Our assessment of, and conclusion on, the effectiveness of internal control over financial reporting as of December 31, 2024, did not include the internal controls of Marathon Oil, acquired in 2024. In the fourth quarter of 2024, we began integrating Marathon Oil into our operations and internal control processes. As the integration progresses, we may modify or change certain processes and procedures which may result in changes to our internal controls over financial reporting.
There have been no other changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. Other Information
Item 1. Legal Proceedings
ConocoPhillips has elected to use a $1 million threshold for disclosing certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party. ConocoPhillips believes proceedings under this threshold are not material to ConocoPhillips' business and financial condition. Applying this threshold, there are no such proceedings to disclose for the quarter ended September 30, 2025. See Note 9 for information regarding other legal and administrative proceedings.
Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in Item 1A of our 2024 Annual Report on Form 10-K.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities

|  |  |  | Millions of Dollars
Period | Total Number of Shares Purchased* | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs
July 1 - 31, 2025 | 4,666,331 |  | $ | 93.82 |  | 4,666,331 |  | $ | 27,568 |
August 1 - 31, 2025 | 4,400,333 |  | 94.97 |  | 4,400,333 |  | 27,150 |
September 1 - 30, 2025 | 4,422,232 |  | 94.50 |  | 4,422,232 |  | 26,732 |
| 13,488,896 |  |  | 13,488,896 |  |

*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
In late 2016, we initiated our current share repurchase program. As of September 30, 2025, we had repurchased $38.3 billion of shares since 2016. In October 2024, our Board of Directors approved an increase from our previous authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate repurchases. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Except as limited by applicable legal requirements, repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares. See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2024 Annual Report on Form 10-K.
Item 5. Other Information
Insider Trading Arrangements
During the three-month period ended September 30, 2025, no officer or director of the company adopted or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement.

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Item 6. Exhibits

10.1* | Letter Agreement with Timothy A. Leach completed November 4, 2025.
10.2* | Amended and Restated Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips.
22 | Subsidiary Guarantors of Guaranteed Securities (incorporated by reference to Exhibit 22 to the Quarterly Report on Form 10-Q of ConocoPhillips filed on August 7, 2025).
31.1* | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2* | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32** | Certifications pursuant to 18 U.S.C. Section 1350.
101.INS* | Inline XBRL Instance Document.
101.SCH* | Inline XBRL Schema Document.
101.CAL* | Inline XBRL Calculation Linkbase Document.
101.LAB* | Inline XBRL Labels Linkbase Document.
101.PRE* | Inline XBRL Presentation Linkbase Document.
101.DEF* | Inline XBRL Definition Linkbase Document.
104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Filed herewith.
**Furnished herewith.

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Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

| CONOCOPHILLIPS
| /s/ Kontessa S. Haynes-Welsh
| Kontessa S. Haynes-Welsh
| Vice President and Controller
November 6, 2025 |

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