Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization
6,935
6,047
Impairments
34
12
Dry hole costs and leasehold impairments
48
151
Accretion on discounted liabilities
240
204
Deferred taxes
249
753
Distributions more (less) than income from equity affiliates
545
920
(Gain) loss on dispositions
(86)
(200)
Other
(18)
16
Working capital adjustments
Decrease (increase) in accounts and notes receivable
656
1,147
Decrease (increase) in inventories
(100)
(114)
Decrease (increase) in prepaid expenses and other current assets
(53)
486
Increase (decrease) in accounts payable
(117)
(837)
Increase (decrease) in taxes and other accruals
395
(1,833)
Net Cash Provided by Operating Activities
15,667
14,702
Cash Flows From Investing Activities
Capital expenditures and investments
(8,801)
(8,365)
Working capital changes associated with investing activities
195
(175)
Acquisition of businesses, net of cash acquired
49
—
Proceeds from asset dispositions
217
613
Net sales (purchases) of investments
(599)
1,860
Other
(11)
(81)
Net Cash Used in Investing Activities
(8,950)
(6,148)
Cash Flows From Financing Activities
Issuance of debt
—
3,787
Repayment of debt
(607)
(1,243)
Issuance of company common stock
(66)
(57)
Repurchase of company common stock
(3,513)
(4,300)
Dividends paid
(2,749)
(4,175)
Other
(131)
(34)
Net Cash Used in Financing Activities
(7,066)
(6,022)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
(28)
(150)
Net Change in Cash, Cash Equivalents and Restricted Cash
(377)
2,382
Cash, cash equivalents and restricted cash at beginning of period
5,899
6,694
Cash, Cash Equivalents and Restricted Cash at End of Period
$
5,522
9,076
Restricted cash of $301 million and $264 million is included in the "Other assets" line of our Consolidated Balance Sheet as of September 30, 2024 and December 31, 2023, respectively.
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 2023 Annual Report on Form 10-K.
Note 2—Inventories
Millions of Dollars
September 30 2024
December 31 2023
Crude oil and natural gas
$
759
676
Materials and supplies
737
722
Total inventories
$
1,496
1,398
Inventories valued on the LIFO basis
$
424
401
Note 3—Acquisitions and Dispositions
Marathon Oil Corporation Announced Acquisition
For discussion regarding our announced acquisition of Marathon Oil Corporation (Marathon Oil), see Note 20.
Alaska Announced Acquisition
In October 2024, after exercising our preferential rights, we signed a purchase and sale agreement for approximately $300 million, subject to customary adjustments, to increase our working interest by approximately 5 percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit from Chevron U.S.A. Inc. and Union Oil Company of California. Our updated working interest in the Kuparuk River Unit will vary from 94 to 99 percent inclusive of satellites and for the Prudhoe Bay Unit will be approximately 36.5 percent. The transaction is expected to close in the fourth quarter of 2024.
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 final consideration for the all-cash transaction was $3.0 billion after customary adjustments (CAD $4.1 billion):
Fair value of consideration
Millions of Dollars
Cash paid
$
2,635
Contingent consideration
320
Final Consideration
$
2,955
The contingent consideration arrangement requires additional consideration to be paid to TotalEnergies EP Canada Ltd. 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. The fair value of the contingent consideration on the acquisition date was $320 million and estimated by applying the income approach. For the nine-month period ended September 30, 2024, we have made payments of $147 million USD under this arrangement, included in the "Other" line within the Financing Activities section of our Consolidated Statement of Cash Flows. See Note 11.
The transaction was accounted for as a business combination under FASB ASC Topic 805 using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. By the end of the first quarter of 2024, we finalized the allocation of the purchase price to specific assets and liabilities. It was based on the fair value of final consideration and the conclusion of the fair value determination of long-lived assets and all other assets acquired and liabilities assumed.
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. The fair values of other assets acquired and liabilities assumed, which included 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 total consideration of $3.0 billion was allocated to the identifiable assets and liabilities based on fair values as of the acquisition date of October 4, 2023.
Recognized amounts of identifiable assets acquired and liabilities assumed
Millions of Dollars
Oil and gas properties
$
3,082
Asset retirement obligations
(112)
Other
(15)
Total identifiable net assets
$
2,955
With the completion of the transaction, we have acquired proved and unproved properties of approximately $2.9 billion and $0.2 billion, respectively.
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, 2023, as if we had completed the acquisition on January 1, 2022.
Millions of Dollars
Three Months Ended
September 30, 2023
Nine Months Ended
September 30, 2023
Supplemental Pro Forma (unaudited)
As Reported
Pro Forma Surmont
Pro Forma Combined
As Reported
Pro Forma Surmont
Pro Forma Combined
Total Revenues and Other Income
$
14,866
697
15,563
43,267
1,989
45,256
Income (loss) before income taxes
4,100
269
4,369
12,024
498
12,522
Net Income (Loss)
2,798
204
3,002
7,950
378
8,328
Earnings per share ($ per share):
Basic net income (loss)
$
2.33
2.50
6.56
6.87
Diluted net income (loss)
2.32
2.49
6.54
6.85
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, 2022, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma financial information for the three- and nine-month periods ended September 30, 2023, is a result of combining the consolidated income statement of ConocoPhillips with the results of the assets acquired from TotalEnergies EP Canada Ltd. The pro forma results do not include transaction-related costs, nor any 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. We believe the estimates and assumptions are reasonable, and the relative effects of the transaction are properly reflected.
In Australia, we hold a 47.5 percent shareholding interest in APLNG. At September 30, 2024, the outstanding balance of APLNG's debt was $4.0 billion under various previously entered facilities. The last principal and interest payment on these facilities is due in September 2030. See Note 7.
At September 30, 2024, the carrying value of our equity method investment in APLNG was approximately $5.0 billion.
Port Arthur LNG (PALNG)
In March 2023, we acquired a 30 percent direct equity investment in PALNG, a joint venture for the development of a large-scale LNG facility. At September 30, 2024, the carrying value of our equity method investment in PALNG was approximately $1.5 billion.
Qatar LNG Projects
Our equity method investments in Qatar include the following:
•QatarEnergy LNG N(3) (N3)—30 percent owned joint venture with an affiliate 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, 2024, the carrying value of our equity method investments in Qatar was approximately $1.2 billion.
During the second quarter of 2024, we were notified that an affiliate of QatarEnergy transferred a 5 percent joint venture interest in NFE4 to an affiliate of China National Petroleum Corporation. As a result, we have concluded NFE4 is a VIE and we are not the primary beneficiary of the VIE because we do not have the power to direct the activities that most significantly impact economic performance of NFE4.
Our debt balance at September 30, 2024 was $18.3 billion, compared with $18.9 billion at December 31, 2023.
In the first quarter of 2024, the company retired $461 million principal amount of our 2.125% Notes at maturity.
Our revolving credit facility provides a total borrowing capacity of $5.5 billion with an expiration date of February 2027. 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, 2024, and at December 31, 2023.
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, 2024, 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.
At September 30, 2024, 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, 2024, we had multiple guarantees outstanding in connection with our 47.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2024 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 six 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, 2024, 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 $700 million ($1.2 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 12 to 21 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $490 million and would become payable if APLNG does not perform. At September 30, 2024, the carrying value of these guarantees was approximately $34 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, 2024, the carrying value of these guarantees was approximately $14 million.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $620 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, 2024, there was no carrying value associated with these guarantees.
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, 2024, was approximately $20 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 8for additional information about environmental liabilities.
Note 8—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 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.
We are currently participating in environmental assessments and cleanups at numerous CERCLA 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 purchase 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 a total environmental accrual of $209 million at September 30, 2024 compared with $184 million at December 31, 2023. 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.
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, 2024, we had performance obligations secured by letters of credit of $236 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, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an ICSID arbitration tribunal ("Tribunal") held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. On August 29, 2019, the Tribunal issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands at $8.5 billion plus interest. The government of Venezuela sought annulment of the award, which automatically stayed enforcement of the award. On September 29, 2021, the ICSID annulment committee lifted the stay of enforcement of the award. The annulment proceedings are underway.
In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $500 million within a period of 90 days from the time of signing the settlement agreement. The balance of the settlement was to be paid quarterly over a period of four and a half years. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach. As a result, ConocoPhillips has resumed legal enforcement actions. To date, ConocoPhillips has received approximately $786 million in connection with the ICC award. ConocoPhillips has ensured that the settlement and any actions taken in enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.
In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded ConocoPhillips approximately $33 million plus interest under the Corocoro contracts. ConocoPhillips is seeking recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the actions related to the award 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.
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 22 of the lawsuits and will vigorously defend against them. On October 17, 2022, the Fifth Circuit affirmed remand of the lead case to state court, and the subsequent request for rehearing was denied. On February 27, 2023, the Supreme Court denied a certiorari petition from the defendants regarding the Fifth Circuit ruling. Accordingly, the federal district courts have issued remands to state court. 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.
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, 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. 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.
Note 9—Suspended Wells and Exploration Expenses
The capitalized cost of suspended wells at September 30, 2024 was $196 million, an increase of $12 million from December 31, 2023. In the third quarter of 2024, a partner operated well completed drilling in the Gulf of Mexico and was suspended pending further analysis. In the first quarter of 2024, after further evaluation, we recognized dry hole expenses of $18 million for the suspended Busta discovery well on license PL782S in the North Sea.
Exploration Expenses
In the second quarter of 2024, we recognized $22 million as dry hole expense primarily for two partner operated exploration wells in the Alvheim area of the Norwegian sector of the North Sea.
We use futures, forwards, swaps and options in various markets to meet our customers' 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 2024
December 31 2023
Assets
Prepaid expenses and other current assets
$
342
611
Other assets
86
113
Liabilities
Other accruals
308
567
Other liabilities and deferred credits
74
80
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
2024
2023
2024
2023
Sales and other operating revenues
$
49
(11)
135
1
Other income
(2)
(5)
(2)
(6)
Purchased commodities
(46)
7
(125)
(49)
The table below summarizes our net exposures resulting from outstanding commodity derivative contracts:
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 our share of PALNG's interest rate swaps designated as a cash flow hedge. For the three- and nine-month periods ended September 30, 2023, we recognized an unrealized gain of $46 million 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, reaching par value at maturity.
•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.
The following investments are carried on our consolidated balance sheet at cost, plus accrued interest, and the table reflects remaining maturities at September 30, 2024, and December 31, 2023:
The following investments in debt securities classified as available for sale are carried at fair value on our consolidated balance sheet at September 30, 2024, and December 31, 2023:
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
Investments and Long-Term Receivables
September 30 2024
December 31 2023
September 30 2024
December 31 2023
September 30 2024
December 31 2023
Major Security Type
Corporate Bonds
$
—
—
330
201
599
606
Commercial Paper
3
—
97
131
U.S. Government Obligations
—
—
62
89
195
189
U.S. Government Agency Obligations
—
5
7
7
Foreign Government Obligations
8
7
4
4
Asset-Backed Securities
18
2
204
183
$
3
—
515
435
1,009
989
Cash and Cash Equivalents and Short-Term Investments have remaining maturities within one year. Investments and Long-Term Receivables have remaining maturities greater than one year through four 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 2024
December 31 2023
September 30 2024
December 31 2023
Major Security Type
Corporate Bonds
$
919
806
929
807
Commercial Paper
100
131
100
131
U.S. Government Obligations
255
278
257
278
U.S. Government Agency Obligations
7
12
7
12
Foreign Government Obligations
12
11
12
11
Asset-Backed Securities
220
184
222
185
$
1,513
1,422
1,527
1,424
As of September 30, 2024 total unrealized gains for debt securities classified as available for sale with net gains were $14 million. As of December 31, 2023, total unrealized gains for debt securities classified as available for sale with net gains were $5 million. 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, 2024, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $142 million and $597 million, respectively. For the three- and nine-month periods ended September 30, 2023, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $258 million and $809 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.
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, 2024, and December 31, 2023, was $62 million and $181 million, respectively. For these instruments, no collateral was posted at September 30, 2024 and December 31, 2023. If our credit rating had been downgraded below investment grade at September 30, 2024, we would have been required to post $38 million of additional collateral, either with cash or letters of credit.
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, 2024, nor during the year ended December 31, 2023.
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. See Note 3.
•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 to TotalEnergies EP Canada Ltd. in connection with the acquisition of the remaining 50 percent working interest in Surmont completed in 2023. Contingent consideration consists of total payments up to approximately $0.4 billion CAD over a five-year term ending in the fourth quarter of 2028. The contingent payments represent $2 million for every dollar that the monthly WCS average pricing exceeds $52 per barrel. The terms include adjustments related to not achieving certain production targets. During the nine-month period ended September 30, 2024, we made payments of approximately $147 million USD to TotalEnergies EP Canada Ltd. under this arrangement. These payments are included in the "Other" line within the Financing Activities section of our Consolidated Statement of Cash Flows. The fair value of the remaining contingent consideration as of September 30, 2024, is calculated using the income approach and is largely based on the estimated commodity price outlook using a combination of external pricing service companies' and our internal price outlook (unobservable input) and a discount rate consistent with those used by principal market participants (observable input). The impact of other unobservable inputs on the fair value as of September 30, 2024, was not significant.
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, 2024
December 31, 2023
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investments in debt securities
$
257
1,270
—
1,527
278
1,146
—
1,424
Commodity derivatives
198
195
35
428
308
301
115
724
Total assets
$
455
1,465
35
1,955
586
1,447
115
2,148
Liabilities
Commodity derivatives
$
251
117
14
382
350
283
14
647
Contingent consideration
—
—
165
165
—
—
312
312
Total liabilities
$
251
117
179
547
350
283
326
959
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, 2024
$
165
Discounted cash flow
Commodity price outlook* ($/BOE)
$50.05 - $61.69 ($54.88)
December 31, 2023
312
$45.48 - $63.04 ($57.45)
*Commodity price outlook based on a combination of external pricing service companies' outlooks and our internal outlook.
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, 2024
Assets
$
428
—
428
245
183
—
183
Liabilities
382
1
381
245
136
53
83
December 31, 2023
Assets
$
724
39
685
375
310
4
306
Liabilities
647
34
613
375
238
47
191
At September 30, 2024 and December 31, 2023, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.
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):
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, 2023
$
(393)
2
(5,344)
62
(5,673)
Other comprehensive income (loss)
14
10
(156)
(40)
(172)
September 30, 2024
$
(379)
12
(5,500)
22
(5,845)
The following table summarizes reclassifications out of accumulated other comprehensive income (loss) and into net income (loss):
Millions of Dollars
Three Months Ended
September 30
Nine Months Ended
September 30
2024
2023
2024
2023
Defined benefit plans*
$
5
9
14
26
*The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $1 million and $2 million for the three-month periods ended September 30, 2024 and September 30, 2023, respectively, and $5 million and $8 million for the nine-month periods ended September 30, 2024 and September 30, 2023, respectively. See Note 14.
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.
During the first nine months of 2024, we contributed $90 million to our domestic benefit plans and $81 million to our international benefit plans.We expect our total contributions in 2024 to be approximately $100 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $95 million to our international qualified and nonqualified pension and postretirement benefit plans.
Note 15—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
Millions of Dollars
Three Months Ended
September 30
Nine Months Ended
September 30
2024
2023
2024
2023
Significant Transactions with Equity Affiliates
Operating revenues and other income
$
23
23
64
67
Operating expenses and selling, general and administrative expenses
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
2024
2023
2024
2023
Revenue from contracts with customers
$
11,703
12,599
36,670
35,578
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative
1,403
1,697
3,971
6,289
Financial derivative contracts
(65)
(46)
(132)
(455)
Consolidated sales and other operating revenues
$
13,041
14,250
40,509
41,412
Revenues from contracts outside the scope of ASC Topic 606 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
2024
2023
2024
2023
Revenue from Contracts Outside the Scope of ASC Topic 606 by Segment
Lower 48
$
1,007
1,478
3,009
5,067
Canada
68
207
376
978
Europe, Middle East and North Africa
328
12
586
244
Physical contracts meeting the definition of a derivative
$
1,403
1,697
3,971
6,289
Millions of Dollars
Three Months Ended
September 30
Nine Months Ended
September 30
2024
2023
2024
2023
Revenue from Contracts Outside the Scope of ASC Topic 606 by Product
Crude oil
$
220
—
273
143
Natural gas
736
1,274
2,650
5,122
Other
447
423
1,048
1,024
Physical contracts meeting the definition of a derivative
$
1,403
1,697
3,971
6,289
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 (or partially unsatisfied) as of the end of the reporting period.
At September 30, 2024, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $3,726 million compared with $4,414 million at December 31, 2023, 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 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 gas sold under contracts for which NPNS has not been elected compared to trade receivables where NPNS has been elected.
Contract Liabilities from Contracts with Customers
We have entered into certain agreements under which we license our proprietary technology, including the Optimized Cascade® process technology, to customers to maximize the efficiency of LNG plants. These agreements typically provide for milestone payments to be made during and after the construction phases of the LNG plant. The payments are not directly related to our performance obligations under the contract and are recorded as deferred revenue to be recognized when the customer is able to benefit from their right to use the applicable licensed technology. Revenue recognized during the three- and nine-month periods ended September 30, 2024, and September 30, 2023, was immaterial. We expect to recognize the outstanding contract liabilities of $45 million as of September 30, 2024, as revenue during the years 2026, 2028 and 2029.
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
2024
2023
2024
2023
Basic earnings per share
Net Income (Loss)
$
2,059
2,798
6,939
7,950
Less: Dividends and undistributed earnings
allocated to participating securities
7
9
21
26
Net Income (Loss) available to common shareholders
$
2,052
2,789
6,918
7,924
Weighted-average common shares outstanding (in millions)
1,161
1,197
1,169
1,208
Net Income (Loss) Per Share of Common Stock
$
1.77
2.33
5.92
6.56
Diluted earnings per share
Net Income (Loss) available to common shareholders
$
2,052
2,789
6,918
7,924
Weighted-average common shares outstanding (in millions)
1,161
1,197
1,169
1,208
Add: Dilutive impact of options and unvested
non-participating RSU/PSUs (in millions)
2
3
2
3
Weighted-average diluted shares outstanding (in millions)
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; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.
Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense; impacts from certain debt transactions; consolidating tax adjustments; corporate overhead and certain technology activities, including licensing revenues; and unrealized holding gains or losses on equity securities. All cash and cash equivalents and short-term investments are included in Corporate and Other.
We evaluate performance and allocate resources based on net income (loss). Intersegment sales are at prices that approximate market.
Analysis of Results by Operating Segment
Millions of Dollars
Three Months Ended
September 30
Nine Months Ended
September 30
2024
2023
2024
2023
Sales and Other Operating Revenues
Alaska
$
1,481
1,801
4,934
5,245
Lower 48
9,080
9,883
27,442
28,321
Intersegment eliminations
—
—
(1)
(5)
Lower 48
9,080
9,883
27,441
28,316
Canada
1,139
1,320
4,136
3,353
Intersegment eliminations
(479)
(512)
(1,599)
(1,253)
Canada
660
808
2,537
2,100
Europe, Middle East and North Africa
1,337
1,211
4,090
4,282
Asia Pacific
478
544
1,495
1,440
Corporate and Other
5
3
12
29
Consolidated sales and other operating revenues
$
13,041
14,250
40,509
41,412
Sales and Other Operating Revenues by Geographic Location*
U.S.
$
10,445
11,550
32,201
33,392
Canada
660
808
2,537
2,100
China
261
225
749
671
Libya
307
392
1,277
1,209
Malaysia
217
319
746
769
Norway
640
589
1,778
1,817
U.K.
510
366
1,217
1,451
Other foreign countries
1
1
4
3
Worldwide consolidated
$
13,041
14,250
40,509
41,412
Sales and Other Operating Revenues by Product
Crude oil
$
9,806
10,027
29,480
27,894
Natural gas
1,290
2,209
4,346
8,481
Natural gas liquids
693
677
2,035
1,954
Other**
1,252
1,337
4,648
3,083
Consolidated sales and other operating revenues by product
$
13,041
14,250
40,509
41,412
*Sales and other operating revenues are attributable to countries based on the location of the selling operation.
Our effective tax rate for the three-month periods ended September 30, 2024, and September 30, 2023, was 36.4 percent and 31.8 percent, respectively. The change in the effective tax rate for the three-month period ended September 30, 2024, is primarily due to a shift in our mix of income among taxing jurisdictions as well as the release of tax reserves and the recognition of a Malaysia tax benefit occurring in the three-month period ending September 30, 2023.
Our effective tax rate for the nine-month periods ended September 30, 2024, and 2023, was 35.2 percent and 33.9 percent, respectively. The change in the effective tax rate for the nine-month period ended September 30, 2024, is primarily due to a release of tax reserves and a recognition of a $52 million Malaysia tax benefit in the nine-month period ending September 30, 2023, partly offset by a shift in our mix of income among our tax jurisdictions and a recognition of a $76 million Malaysia tax benefit.
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.
During the third quarter of 2023, we received legislative approval in the Malaysia Block J to claim a deepwater investment tax incentive. As a result, we recorded an income tax benefit of $52 million.
During the third quarter of 2023, the Canada Revenue Agency closed the 2018 domestic audit of one of our Canadian subsidiaries. As a result, we recognized a Canadian tax benefit of $92 million relating to our disposition of certain Canadian assets that was previously offset by a full reserve.
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—Pending Acquisition of Marathon Oil Corporation
On May 28, 2024, we entered into a definitive agreement (the Merger Agreement) with Marathon Oil to acquire all of its outstanding shares in an all-stock transaction, pursuant to which Marathon Oil stockholders will receive 0.255 shares of ConocoPhillips common stock for each Marathon Oil share. The transaction was unanimously approved by the boards of directors of both companies. On August 29, 2024, Marathon Oil announced that its stockholders had approved the transaction. We are working to complete the merger as soon as practicable and continue to anticipate closing late in the fourth quarter of 2024, subject to regulatory clearances and other customary closing conditions. See Item 1A. Risk Factors.
Note 21—New Accounting Standards
In November 2023, the FASB issued ASU No. 2023-07, “Improvements to Reportable Segment Disclosures” which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 “Segment Reporting.” The amendments do not change how we identify our operating segments. On adoption, the disclosure improvements will be applied retrospectively to prior periods presented. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, and early adoption is permitted. We are currently evaluating the impact of the adoption of this ASU.
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.
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 50.
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 13 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, 2024, we employed approximately 10,300 people worldwide and had total assets of $97 billion.
Pending Acquisition of Marathon Oil Corporation
In May 2024, we announced a definitive agreement (the Merger Agreement) to acquire Marathon Oil Corporation (Marathon Oil) in an all-stock transaction (the Marathon Oil acquisition), inclusive of Marathon Oil's debt of approximately $5.3 billion at June 30, 2024. Under the terms of the Merger Agreement, which has been unanimously approved by the boards of directors of each company, Marathon Oil stockholders will receive 0.255 shares of ConocoPhillips common stock for each Marathon Oil share. We expect that the Marathon Oil acquisition will add high-quality, low cost of supply, development opportunities to our existing U.S. onshore portfolio and additional LNG capacity to our global LNG portfolio. On August 29, 2024, Marathon Oil announced that its stockholders had approved the transaction. We anticipate closing late in the fourth quarter of 2024, subject to regulatory clearances and other customary closing conditions. See Item 1A. Risk Factors.
In May 2024, as part of our Marathon Oil acquisition announcement, we stated that we expected at least $500 million in synergies, within the first full year following the close of the transaction. We now expect to reflect synergies that significantly exceed our initial $500 million guidance. Concurrent with our Marathon Oil acquisition announcement, we detailed a plan to repurchase over $7 billion of shares in the first full year following the closing of the transaction and over $20 billion of shares in total over the first three years, based on commodity prices at the time of the announcement. Through this plan we expect to retire the equivalent amount of newly issued equity from the transaction in two to three years. Further, in conjunction with the Marathon Oil acquisition announcement, we announced a plan to dispose of approximately $2 billion of assets across the portfolio pursuant to ongoing high-grading and optimization efforts.
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, OPEC Plus supply updates, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.
The macro-environment of the global energy industry, including the energy transition, continues to evolve. We believe ConocoPhillips will continue to play an essential role by executing on three objectives: responsibly meeting energy transition pathway demand, delivering competitive returns on and of capital and progressing toward our net-zero operational emissions ambition. We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders.
Our Triple Mandate and our foundational principles guide our differential value proposition to deliver competitive returns to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance.
In the third quarter, we announced further growth to our global LNG portfolio. In July, we entered into an 18-year agreement securing regasification capacity at the Zeebrugge LNG terminal in Belgium which includes regasification services for approximately 0.75 MTPA of LNG beginning in 2027. In July, we also entered into a long-term LNG sales agreement for approximately 0.5 MTPA into Asia starting in 2027. These agreements provide additional access to both the European and Asian natural gas markets.
We continue to optimize our portfolio geared towards our returns-focused value proposition. In October, we signed an agreement to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit in Alaska. This transaction is expected to close in the fourth quarter of 2024. See Note 3.
In October, we declared a fourth-quarter ordinary dividend of $0.78 per share, representing an increase of 34 percent which incorporates the prior VROC equivalent of $0.20 per share. We also reconfirmed our 2024 planned return of capital to shareholders of at least $9 billion. Additionally in October, our Board of Directors approved an increase to our existing share repurchase program authorization by the lesser of $20 billion or the number of shares issued in the Marathon Oil transaction.
Production was 1,917 MBOED in the third quarter of 2024, an increase of 111 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, third-quarter2024 production increased by 47 MBOED or three percent from the same period a year ago.
Third-quarter 2024 production resulted in $5.8 billion of cash provided by operating activities. We returned $1.2 billion to shareholders through share repurchases and $0.9 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents, restricted cash and short-term investments totaling $7.1 billion and long-term investments in debt securities of $1.0 billion.
Also in the third quarter of 2024, 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.
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, tax regulations, 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 Henry Hub natural gas:
Brent crude oil prices averaged $80.18 per barrel in the third quarter of 2024, a decrease of eight percent compared with $86.76 per barrel in the third quarter of 2023. WTI at Cushing crude oil prices averaged $75.10 per barrel in the third quarter of 2024, a decrease of nine percent compared with $82.26 per barrel in the third quarter of 2023. Oil prices were lower in the third quarter of 2024 due to slower global demand growth relative to the third quarter of 2023 and higher supplies from non-OPEC Plus countries.
Henry Hub natural gas prices averaged $2.15 per MMBTU in the third quarter of 2024, a decrease of 15 percent compared with $2.54 per MMBTU in the third quarter of 2023. Henry Hub prices decreased due to excess North American natural gas storage levels following a mild 2023-2024 winter. Lower 48 segment realized natural gas prices decreased to $0.18 per MCF in the third quarter of 2024 driven by lower regional prices related to pipeline capacity constraints.
Our realized bitumen price averaged $47.32 per barrel in the third quarter of 2024, a decrease of 18 percent compared with $57.85 per barrel in the third quarter of 2023. The decrease in the third quarter of 2024 was driven by widening WCS differentials in Canada, lower heavy oil refinery demand on the U.S. Gulf Coast and impacts associated with lower sales volumes from Surmont due to a planned turnaround at one of our central processing facilities.
For the third quarter of 2024, our total average realized price was $54.18 per BOE compared with $60.05 per BOE in the third quarter of 2023.
•Reported third-quarter 2024 earnings per share of $1.76;
•Generated cash provided by operating activities of $5.8 billion;
•Raised ordinary dividend by 34 percent to $0.78 per share and increased existing share repurchase authorization by up to $20 billion;
•Delivered total company production of 1,917 MBOED;
•Achieved record lower 48 production of 1,147 MBOED, including 781 MBOED from the Permian, 246 MBOED from the Eagle Ford and 107 MBOED from the Bakken;
•Successfully completed planned turnarounds, primarily in Canada and the Lower 48;
•Exercised preferential rights and signed an agreement to acquire additional working interests in the Kuparuk River and Prudhoe Bay units in Alaska for approximately $300 million, with expected close by year-end, subject to customary closing conditions;
•Distributed $2.1 billion to shareholders, including $1.2 billion through share repurchases and $0.9 billion through the ordinary dividend and VROC;
•Ended the quarter with cash, cash equivalents, restricted cash and short-term investments of $7.1 billion and long-term investments of $1.0 billion.
Outlook
Production, Capital and DD&A
Fourth-quarter 2024 production is expected to be 1.99 to 2.03 MMBOED. Full-year production is expected to be approximately 1.94 to 1.95 MMBOED, as compared to prior guidance of 1.93 to 1.94 MMBOED.
All other guidance items remain unchanged.
Guidance excludes any impact from previously announced transactions.
Unless otherwise indicated, discussion of consolidated results for the three- and nine-month periods ended September 30, 2024, is based on a comparison with the corresponding period of 2023.
General administrative, geological and geophysical,
lease rental and other
$
70
43
236
162
Leasehold impairment
—
12
4
42
Dry holes
—
37
44
109
$
70
92
284
313
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, 2024, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.
Total production in the third quarter of 2024 was 1,917 MBOED, an increase of 111 MBOED or six percent from the same period a year ago. Total production in the nine-month period of 2024 was 1,921 MBOED, an increase of 120 MBOED or seven percent from the same period a year ago. Production increases include:
•New wells online in the Lower 48, Alaska, Australia, Canada, China, Libya and Norway.
•Our Surmont acquisition, which closed in October 2023. See Note 3.
Production increases were partially offset by:
•Normal field decline.
•Planned turnaround activity across our global operations.
After adjusting for impacts from closed acquisitions and dispositions, third-quarter2024 production increased by 47 MBOED or three percent from the same period a year ago. After adjusting for closed acquisitions and dispositions, production in the nine-month period of 2024 increased 55 MBOED or three percent from the same period a year ago.
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
2024
2023
2024
2023
Sales and other operating revenues
$
13,041
14,250
40,509
41,412
Gain (loss) on dispositions
(2)
108
86
200
Purchased commodities
4,747
5,543
14,939
16,297
Production and operating expenses
2,261
1,995
6,440
5,660
Depreciation, depletion and amortization
2,390
2,095
6,935
6,047
Taxes other than income taxes
476
536
1,567
1,624
Sales and other operating revenues decreased $1,209 million in the third quarter of 2024 and decreased $903 million in the nine-month period of 2024, respectively. Decreases in the third quarter were due to lower realized prices of $865 million, partially offset by higher volumes of $404 million. Decreases in the nine-month period of 2024 were due to lower realized natural gas prices of $642 million, partially offset by higher volumes of $1,368 million. Additional decreases to revenues in both the three- and nine-month periods of 2024 resulted from the timing of sales as compared with the corresponding periods of 2023.
Gain (loss) on dispositions decreased $110 million in the third quarter of 2024 and $114 million in the nine-month period of 2024 primarily due to the absence of the divestiture of an equity investment in our Lower 48 segment.
Purchased commodities for the three- and nine-month periods of 2024 decreased $796 million and $1,358 million, respectively. The third quarter of 2024 decrease was driven by lower gas and crude prices, partially offset by higher crude volumes. The nine-month period of 2024 decrease was driven by lower gas prices, partially offset by higher crude volumes.
Production and operating expenses for the three- and nine-month periods of 2024 increased $266 million and $780 million, respectively, due to higher lease operating expenses, transportation related costs and well work activities in our Lower 48 and Alaska segments, higher volumes primarily in our Canada and Lower 48 segments as well as higher expenses associated with the Surmont turnaround in our Canada segment.
DD&A expenses for the three- and nine-month periods of 2024 increased $295 million and $888 million, respectively, mainly due to higher rates in our Lower 48 and Alaska segments and higher volumes primarily in our Canada and Lower 48 segments.
Unless otherwise indicated, discussion of segment results for the three- and nine-month periods ended September 30, 2024, is based on a comparison with the corresponding period of 2023 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
2024
2023
2024
2023
Alaska
$
267
448
973
1,236
Lower 48
1,241
1,781
3,881
4,863
Canada
25
186
466
224
Europe, Middle East and North Africa
298
253
853
882
Asia Pacific
455
465
1,411
1,374
Other International
1
(2)
3
(5)
Corporate and Other
(228)
(333)
(648)
(624)
Net income (loss)
$
2,059
2,798
6,939
7,950
For further discussion of segment results, see the following pages.
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2024, Alaska contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.
Net Income (Loss)
Alaska reported earnings of $267 million and $973 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $448 million and $1,236 million in the three- and nine-month periods of 2023, respectively.
Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $68 million, lower volumes of $16 million. Decreases to earnings in the third quarter of 2024 included higher DD&A expenses of $36 million due to higher rates as a result of prior year-end downward reserve revisions and higher production and operating expenses of $33 million driven by higher lease operating expenses and well work activity. The decreases to earnings were partially offset by lower taxes other than income taxes of $38 million due to lower taxes driven by increased capital expenditures.
Earnings in the nine-month period of 2024 included lower revenues resulting from lower volumes of $55 million, partially offset by higher realized prices of $80 million. Decreases to earnings in the nine-month period of 2024 included higher DD&A expenses of $123 million due to higher rates as a result of year-end downward reserve revisions, higher production and operating expenses of $83 million driven by higher well work activity and lease operating expenses. The decreases to earnings were partially offset by lower taxes other than income taxes of $47 million due to lower taxes driven by increased capital expenditures.
Production
Average production decreased 3 MBOED and 4 MBOED in the three- and nine-month periods of 2024, respectively. Decreases to production were primarily due to normal field decline, partially offset by new wells online.
Planned Acquisition
In October, we signed an agreement to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit. This transaction is expected to close in the fourth quarter of 2024. See Note 3.
The Lower 48 segment consists of operations located in the U.S. Lower 48 states, producing properties in the Gulf of Mexico and commercial operations. As of September 30, 2024, the Lower 48 contributed 63 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.
Net Income (Loss)
Lower 48 reported earnings of $1,241 million and $3,881 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $1,781 million and $4,863 million in the three- and nine-month periods of 2023, respectively.
Earnings in the third quarter of 2024 included lower revenues resulting from lower overall realized prices of $494 million, partially offset by higher volumes of $190 million. Decreases to earnings in the third quarter of 2024 included higher DD&A expenses of $118 million, driven by higher volumes of $64 million and higher rates of $52 million, the absence of a gain from the divestiture of an equity investment of $100 million and higher production and operating expenses of $40 million driven by increased transportation related costs of $30 million.
Earnings in the nine-month period of 2024 included lower revenues resulting from lower overall realized prices of $433 million, partially offset by higher volumes of $287 million. Decreases to earnings in the nine-month period of 2024 included higher DD&A expenses of $323 million, driven by higher volumes of $166 million and higher rates of $160 million, higher production and operating expenses of $235 million, driven by increased transportation related costs of $93 million and increased lease operating expenses of $74 million, and the absence of a gain from the divestiture of an equity investment of $100 million.
Production
Average production increased 64 MBOED and 38 MBOED in the three- and nine-month periods of 2024, respectively. 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 increases were partly offset by normal field decline.
*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, 2024, Canada contributed 10 percent of our consolidated liquids production and five percent of our consolidated natural gas production.
Net Income (Loss)
Canada reported earnings of $25 million and $466 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $186 million and $224 million in the three- and nine-month periods of 2023, respectively.
Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $49 million, partially offset by higher volumes of $104 million driven by our increased working interest in Surmont. Additional decreases to revenues resulted from the timing of sales as compared with the corresponding period of 2023. Decreases to earnings in the third quarter of 2024 included the absence of a $92 million third-quarter 2023 tax benefit recognized upon the closing of a Canada Revenue Agency audit, higher production and operating expenses of $89 million, driven by $61 million related to our increased working interest in Surmont and $50 million in expenses associated with a third quarter planned turnaround at Surmont, and higher DD&A expenses of $40 million.
Earnings in the nine-month period of 2024 included higher revenues resulting from higher volumes of $666 million, driven by our increased working interest in Surmont, and higher realized prices of $76 million. Decreases to earnings in the nine-month period of 2024 included higher production and operating expenses of $231 million, driven by $160 million related to our increased working interest in Surmont and $61 million in expenses associated with a third quarter planned turnaround at Surmont, higher DD&A expenses of $156 million, driven by higher volumes, and the absence of a $92 million third-quarter 2023 tax benefit recognized upon the closing of a Canada Revenue Agency audit.
Production
Average production increased 44 MBOED and 72 MBOED in the three- and nine-month periods of 2024, respectively. Increases to production resulted from our increased working interest in Surmont as well as new wells online in the Montney and Surmont. See Note 3.
Production increases were partly offset by planned turnaround activity at a Surmont central processing facility and normal field decline.
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 and commercial and terminalling operations in the U.K. As of September 30, 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.
Net Income (Loss)
Europe, Middle East and North Africa reported earnings of $298 million and $853 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $253 million and $882 million in the three- and nine-month periods of 2023, respectively.
Earnings in the third quarter of 2024 included higher revenues resulting from higher volumes of $31 million, partially offset by lower realized prices of $11 million primarily impacted by lower crude prices.
Earnings in the nine-month period of 2024 included lower revenues resulting from lower realized prices of $72 million primarily impacted by lower natural gas prices, partially offset by higher volumes of $54 million. Decreases to earnings included lower foreign exchange gains of approximately $37 million and higher DD&A expenses of $34 million.
Consolidated Production
Average consolidated production increased 16 MBOED and 11 MBOED in the three- and nine-month periods of 2024, respectively. Increases to production were primarily due to new wells online and improved performance in both Norway and Libya.
Production increases were partly offset by normal field decline and curtailed production in Libya due to the force majeure at Es Sider terminal. Force majeure was lifted in early October.
Exploration Activity
In the nine-month period of 2024, we charged approximately $40 million before-tax as dry hole expenses primarily for two partner operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea and the Busta suspended discovery well on license PL782S that was drilled in 2019.
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, 2024, 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 $455 million and $1,411 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $465 million and $1,374 million in the three- and nine-month periods of 2023, respectively.
Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $41 million and lower volumes of $38 million. Decreases to earnings included the absence of a $52 million tax benefit associated with a deepwater tax incentive. The decreases to earnings were partially offset by higher earnings from equity affiliates of $38 million and foreign exchange gains of $30 million. See Note 19.
Earnings in the nine-month period of 2024 included a $76 million tax benefit associated with deepwater investment tax incentive, higher foreign exchange gains of approximately $38 million and lower DD&A expenses of $21 million. The increases to earnings were partially offset by the absence of a $52 million third quarter 2023 tax benefit associated with a deepwater investment tax incentive and lower earnings from equity affiliates of $50 million. See Note 19.
Consolidated Production
Average consolidated production decreased 6 MBOED and 2 MBOED in the three- and nine-month periods of 2024, respectively. Decreases to production were primarily due to normal field decline.
Production decreases were partly offset by Bohai Bay development activity in China.
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
2024
2023
2024
2023
Net Income (Loss)
Net interest expense
$
(79)
(91)
(261)
(267)
Corporate general and administrative expenses
(99)
(87)
(282)
(273)
Technology
(32)
(14)
(100)
(19)
Other income (expense)
(18)
(141)
(5)
(65)
$
(228)
(333)
(648)
(624)
Net interest expense consists of interest and financing expense, net of interest income and capitalized interest.
Corporate G&A expenses include compensation programs and staff costs.
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. Earnings in Technology for the nine-month period of 2024 decreased due to increased costs in low-carbon and other new technologies and lower licensing revenues.
Other income (expense) or “Other” 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/losses on the early retirement of debt, holding gains or losses on equity securities and pension settlement expense. “Other” increased in third quarter of 2024 primarily due to the absence of a 2023 consolidating tax adjustment and absence of 2023 foreign currency exchange losses.
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 2024, the primary uses of our available cash were $8.8 billion to support our ongoing capital expenditures and investments program, $3.5 billion to repurchase common stock, $2.7 billion to pay the ordinary dividend and VROC, $0.6 billion to retire debt at maturity and $0.6 billion net purchases of investments.
At September 30, 2024, we had total liquidity of $12.3 billion, comprised of cash and cash equivalents of $5.2 billion, short-term investments of $1.6 billion and available borrowing capacity under our credit facility of $5.5 billion. In addition, we have $1.0 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 was $15.7 billion for the first nine months of 2024, compared with $14.7 billion for the corresponding period of 2023. The increase is primarily due to changes in operational working capital, driven by lower Norway tax payments and deferral of certain 2024 U.S. income tax payments, alongside higher production, primarily from the Lower 48 and the Surmont 50 percent working interest acquired in the fourth quarter of 2023, partly offset by lower commodity prices and lower distributions from equity affiliates.
Our short-term and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no 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 production volumes, as well as product and location mix, impacts 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; 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 manage for these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.
To maintain or grow our production volumes, we must continue to add to our proved reserve base. See the “Capital Expenditures and Investments” section.
For the first nine months of 2024, we invested $8.8 billion in capital expenditures and investments. Our 2024 operating plan capital expenditures are currently expected to be approximately $11.5 billion. Our 2023 capital expenditures and investments were $11.2 billion. See the “Capital Expenditures and Investments” section.
In the third quarter of 2024, we signed a purchase and sale agreement for approximately $300 million, subject to customary adjustments, to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit in Alaska. This transaction is expected to close in the fourth quarter of 2024. See Note 3.
In the first nine months of 2024, we invested $0.7 billion in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4) and QatarEnergy LNG NFS(3) (NFS3).
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 and 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 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 greater than one year.
Investing activities in the first nine months of 2024 included net purchases of $599 million of investments. We had net purchases of $205 million of short-term investments and net purchases of $394 million of long-term investments. See Note 13.
Financing Activities
We have a revolving credit facility totaling $5.5 billion with an expiration date of February 2027. 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, 2024.
Our debt balance at September 30, 2024 was $18.3 billion compared with $18.9 billion at December 31, 2023. The current portion of debt, including future payments for finance leases, is $1.3 billion at September 30, 2024. In the first quarter of 2024, the company retired $461 million principal amount of our 2.125% Notes at maturity. 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, 2024, and December 31, 2023, we had direct bank letters of credit of $236 million and $340 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.
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.
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. In connection with the pending transaction with Marathon Oil, share repurchases were restricted for a period of time pursuant to SEC regulations. These restrictions ended after the Marathon Oil stockholder approval on August 29, 2024 and share repurchases were subsequently resumed. We anticipate achieving at least $9 billion return of capital in 2024. See Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
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 the first nine months of 2023, we paid ordinary dividends of $1.53 per share and VROC payments of $1.90 per share.
In October 2024, we declared an increase to our quarterly ordinary dividend from $0.58 per share to $0.78 per share, representing a 34 percent increase, effectively rolling the amount of the prior quarter VROC into the ordinary dividend. VROC remains a discretionary option in elevated price environments. The dividend is payable December 2, 2024, to shareholders of record on November 11, 2024.
In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase to our existing authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in the Marathon Oil transaction, such that the Company is not to exceed $65 billion in aggregate purchases. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. As of September 30, 2024, share repurchases since the inception of our current program totaled 414.2 million shares and $32.3 billion. In the nine months ended September 30, 2024, we repurchased 30.8 million shares for a cost of $3.5 billion.
See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2023 Annual Report on Form 10-K.
Capital Expenditures and Investments
Millions of Dollars
Nine Months Ended September 30
2024
2023
Alaska
$
2,102
1,140
Lower 48
4,918
4,878
Canada
419
345
Europe, Middle East and North Africa
694
834
Asia Pacific
235
245
Corporate and Other
433
923
Capital expenditures and investments
$
8,801
8,365
During the first nine months of 2024, 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 activities across assets in Norway.
•Continued development activities in Malaysia and China.
•Investments in PALNG, NFE4 and NFS3.
Our 2024 operating plan capital expenditure guidance is currently expected to be approximately $11.5 billion. Our operating plan capital was $11.2 billion in 2023.
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, 2024
Revenues and Other Income
$
26,849
Income (loss) before income taxes*
6,779
Net Income (Loss)
6,939
*Includes approximately $6.3 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.
Summarized Balance Sheet Data
Millions of Dollars
September 30 2024
December 31 2023
Current Assets
$
6,442
8,008
Amounts due from Non-Obligated Subsidiaries, current
1,491
1,565
Noncurrent Assets
102,119
91,155
Amounts due from Non-Obligated Subsidiaries, noncurrent
10,956
8,936
Current Liabilities
10,415
7,337
Amounts due to Non-Obligated Subsidiaries, current
6,282
3,990
Noncurrent Liabilities
54,731
49,105
Amounts due to Non-Obligated Subsidiaries, noncurrent
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 8.
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. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 56–58 of our 2023 Annual Report on Form 10-K.
We occasionally receive requests for information or notices of potential liability from the 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, 2024, there were 15 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 a total environmental accrual of $209 million at September 30, 2024, compared with $184 million at December 31, 2023. 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.
See Part I—Item 1A—Risk Factors – "We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations," in our 2023 Annual Report on Form 10-K andNote 8 for information on environmental litigation.
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 and regulations focusing on GHG or methane emissions reduction. These proposed or promulgated 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. For examples of legislation and precursors for possible regulation that do or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58–59 of our 2023 Annual Report on Form 10-K.
In 2020, we adopted a climate-related risk framework with an ambition to reduce our operational (Scope 1 and 2) emissions to net-zero by 2050. 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, technologies for emissions reduction, alternative energy technologies and changes in consumer trends. The strategy sets out our choices around portfolio composition, emissions reductions, targets and incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.
An important component of our Climate Risk Strategy is the Plan for the Net-Zero Energy Transition (the 'Plan'). The Plan outlines how we intend to play a valued role in the energy transition by executing on our Triple Mandate to: reliably and responsibly meet energy transition pathway demand, deliver competitive returns on and of capital and progress toward our net-zero operational emissions ambition. The Plan also outlines how we intend to apply our strategic capabilities and resources to meet the challenges posed by climate change in an economically viable, accountable and actionable way that balances the interests of our stakeholders.
Key elements of the Plan include:
•Maintaining strategic flexibility
◦Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet transition pathway energy demand.
◦Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.
◦Track the energy transition through a comprehensive scenario planning process to calibrate and understand alternative energy transition pathways and test the resilience of our corporate strategy to climate risk.
•Reducing Scope 1 and 2 emissions
◦Setting targets for emissions over which we have ownership and control, with an ambition to become a net-zero company for Scope 1 and 2 emissions by 2050.
•Addressing Scope 3 (end-use) emissions
◦Advocating for a well-designed, economy-wide price on carbon and engaging in development of other policy and legislation to address end-use emissions.
◦Working with our suppliers and commercial partners to reduce emissions along the value chain.
•Contributing to an orderly transition
◦Building an attractive LNG portfolio as an important component of responsibly meeting energy transition demand due to its lower GHG emissions than coal used for electricity generation.
◦Evaluating potential investments in emerging energy transition and low-carbon technologies.
Our Plan does not include a Scope 3 (end-use) emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions. This is why we have consistently taken a prominent role in advocating for a well-designed, economy-wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct regulation of methane.
In support of addressing our Scope 1 and 2 emissions, since 2023, we made progress in several key areas:
•Improved our GHG target framework by accelerating our GHG emissions intensity reduction target to 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.
•Achieved the Gold Standard Pathway for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative.
•Continued methane emissions reductions activities in support of our near-zero methane emissions intensity (1.5 kilogram carbon dioxide equivalent per BOE) and introduced data quality improvements.
•Remained on schedule to meet a target of zero routine flaring by the end of 2025, five years sooner than the World Bank Initiative's goal of 2030.
Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technology organization. See Part I—Item 1A—Risk Factors – "Existing and future laws, regulations and internal initiatives relating to global climate changes, such as limitations on GHG emissions, may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products,"and "Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation,"in our 2023 Annual Report on Form 10-K andNote 8 for information on climate change litigation.
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 the Marathon Oil acquisition, the anticipated impact of the proposed transaction on the combined company’s business and future financial and operating results, the expected amount and timing of synergies from the proposed transaction and the anticipated closing date for the proposed transaction 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 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 the 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, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. 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:
•Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels.
•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, including the conflicts in Ukraine and the Middle East, and the global response to such conflict; security threats on facilities and infrastructure; a public health crisis; from 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 impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.
•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 reserves replacement rates, whether as a result of the significant declines in commodity prices or otherwise.
•Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
•Unexpected changes in costs, inflationary pressures or technical requirements for constructing, modifying or operating E&P facilities.
•Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, water disposal or LNG exports.
•Significant operational or investment changes imposed by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce GHG emissions.
•Substantial investment in and development of or use of competing or alternative energy sources, including as a result of existing or future environmental rules and regulations.
•The impact of broader societal attention to and efforts to address climate change may impact our access to capital and insurance.
•Potential failures or delays in delivering on our current or future low-carbon strategy, including our inability to develop new technologies.
•The impact of public health crises, including pandemics (such as COVID-19) and epidemics, and any related company or government policies or actions.
•Lack of, or disruptions in, adequate and 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.
•Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future E&P and LNG development in a timely manner (if at all) or on budget.
•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 and information technology failures, constraints or disruptions.
•Changes in international monetary conditions and foreign currency exchange rate fluctuations.
•Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs, carbon and any materials or products (such as aluminum and steel) used in the operation of our business, including any sanctions imposed as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.
•Liability for remedial actions, including removal and reclamation obligations, under existing and future environmental regulations and litigation.
•Liability resulting from litigation, including litigation directly or indirectly related to the transaction with Concho Resources Inc., or our failure to comply with applicable laws and regulations.
•General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, NGLs and carbon pricing, including the imposition of price caps; regulation or taxation; and other political, economic or diplomatic developments, including as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.
•Volatility in the commodity futures markets.
•Changes in tax and other laws, regulations (including alternative energy mandates) or royalty rules applicable to our business.
•Competition and consolidation in the oil and gas E&P industry, including competition for personnel and equipment.
•Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets or investment sentiment, including as a result of increased societal attention to and efforts to address climate change.
•Our inability to execute, or delays in the completion of, the Marathon Oil acquisition or any other asset dispositions or acquisitions we elect to pursue.
•Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals, consents or authorizations for the Marathon Oil acquisition or for any other pending or future asset dispositions or acquisitions, or that such approvals, consents or authorizations for such disposition or acquisition may be subject to conditions neither we nor Marathon Oil anticipated or may require modification to the terms of the transactions or the operation of our remaining business.
•Our or Marathon Oil’s inability to receive other requisite approvals for the Marathon Oil acquisition or, to satisfy other closing conditions on a timely basis or at all or the failure of the Marathon Oil acquisition to close for any other reason or to close on anticipated terms, including the anticipated tax treatment.
•Potential disruption of our operations as a result of the Marathon Oil acquisition or other pending or future asset dispositions or acquisitions, including the diversion of management time and attention.
•Our inability to realize anticipated cost savings and capital expenditure reductions, including our inability to achieve the expected benefits and synergies from the Marathon Oil acquisition in a timely manner, or at all.
•Our inability to successfully integrate Marathon Oil’s business and technologies, which may result in the combined company not operating as effectively and efficiently as expected.
•Unanticipated difficulties or expenditures relating to the Marathon Oil acquisition.
•Negative effects of the pendency or completion of the Marathon Oil acquisition on our or Marathon Oil’s business relationships and business operations generally.
•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 currently anticipate, if at all.
•The operation and financing 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.
•The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or involuntary, required to mitigate this physical constraint.
•The risk that we or Marathon Oil will be unable to retain and hire key personnel.
•Uncertainty as to the long-term value of our common stock.
•The factors generally described in Part I—Item 1A in our 2023 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information about market risks for the nine months ended September 30, 2024 does not differ materially from that discussed under Item 7A in our 2023 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, 2024, 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, 2024.
In the third quarter of 2023, we began a multi-year implementation of an updated global enterprise resource planning system (ERP). As a result, we have made corresponding changes to our business processes and information systems, updating applicable internal controls over financial reporting where necessary. As the phased implementation of the ERP system progresses, we expect to continue to modify or change certain processes and procedures which may result in further 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, 2024. See Note 8 for information regarding other legal and administrative proceedings.
Other than the risk factors set forth below, there have been no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.
Risks Related to the Proposed Acquisition of Marathon Oil
Our ability to complete the Marathon Oil acquisition is subject to various closing conditions, including regulatory clearances, which may impose conditions that could adversely affect us or cause the acquisition not to be completed.
On May 28, 2024, we entered into the Merger Agreement to acquire Marathon Oil. The Marathon Oil acquisition is subject to a number of conditions to closing as specified in the Merger Agreement. These closing conditions include, among others:
•The expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act) and certain non-U.S. antitrust approvals; and
•The absence of any governmental order or law that makes consummation of the Marathon Oil acquisition illegal or otherwise prohibited.
On July 11, 2024, both ConocoPhillips and Marathon Oil each received a request for additional information and documentary materials (Second Request) from the Federal Trade Commission (FTC) in connection with the FTC's review of the merger. Issuance of the Second Request extends the waiting period imposed by the HSR Act until 30 days after both companies have substantially complied with the Second Request, unless that period is terminated sooner by the FTC.
No assurance can be given that the regulatory clearances be obtained or that the other required conditions to closing will be satisfied, and, if all required clearances are obtained and the required conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such approvals and clearances, including whether any required conditions will materially adversely affect the combined company following the acquisition. Any delay in completing the Marathon Oil acquisition could cause the combined company not to achieve, or to be delayed in achieving, some or all of the expected benefits and synergies from the acquisition. We can provide no assurance that these conditions will not result in the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and the trading price of our common stock.
The termination of the Merger Agreement could negatively impact our business.
If the Marathon Oil acquisition is not completed for any reason, our ongoing business may be adversely affected and, without realizing any of the expected benefits of having completed the Marathon Oil acquisition, we would be subject to a number of risks, including the following:
•We may experience negative reactions from the financial markets, including negative impacts on our stock price;
•We may experience negative reactions from our commercial and vendor partners and employees; and
•Despite our rights to receive termination fees under certain circumstances, we may be required to pay certain costs relating to the Marathon Oil acquisition, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Marathon Oil acquisition is completed, and such termination fees, if any, we receive may be insufficient to cover all such expenses.
Whether or not the Marathon Oil acquisition is completed, the pendency of the Marathon Oil acquisition could cause disruptions in our business, which could have an adverse effect on our business and financial results.
Whether or not the Marathon Oil acquisition is completed, the pendency of the Marathon Oil acquisition could cause disruptions in our business. Specifically:
•Our and Marathon Oil’s current and prospective employees will experience uncertainty about their future roles with the combined company, which might adversely affect the two companies’ abilities to retain key managers and other employees;
•Uncertainty regarding the completion of the Marathon Oil acquisition may cause our and Marathon Oil’s commercial and vendor partners or others that deal with us or Marathon Oil to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Marathon Oil, which could negatively affect our respective revenues, earnings and cash flows; and
•The attention of our and Marathon Oil’s management may be directed toward the completion of the Marathon Oil acquisition, as well as integration planning, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to our business.
We have and will continue to divert significant management resources in an effort to complete the Marathon Oil acquisition and are subject to restrictions contained in the Merger Agreement on the conduct of our business. If the Marathon Oil acquisition is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit.
The market value of our common stock could decline if large amounts of our common stock are sold following the Marathon Oil acquisition.
If the Marathon Oil acquisition is consummated, ConocoPhillips will issue shares of ConocoPhillips common stock to former Marathon Oil stockholders. Former Marathon Oil stockholders may decide not to hold the shares of ConocoPhillips common stock that they will receive in the Marathon Oil acquisition, and ConocoPhillips stockholders may decide to reduce their investment in ConocoPhillips as a result of the changes to ConocoPhillips’ investment profile as a result of the Marathon Oil acquisition. Other Marathon Oil stockholders, such as funds with limitations on their permitted holdings of stock in individual issuers, may be required to sell the shares of ConocoPhillips common stock that they receive in the Marathon Oil acquisition. Such sales of ConocoPhillips common stock could have the effect of depressing the market price for ConocoPhillips common stock.
Combining our business with Marathon Oil’s may be more difficult, costly or time-consuming than expected and
the combined company may fail to achieve the expected benefits and synergies of the Marathon Oil acquisition, which may adversely affect the combined company’s business results and negatively affect the value of the combined company’s common stock.
The success of the Marathon Oil acquisition will depend on, among other things, the ability of the two companies to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. The combined company may encounter difficulties in integrating our and Marathon Oil’s businesses and realizing the expected benefits and synergies of the Marathon Oil acquisition. If the combined company is not able to successfully achieve these objectives, the anticipated benefits of the Marathon Oil acquisition may not be realized fully, or at all, or may take longer to realize than expected.
The Marathon Oil acquisition involves the combination of two companies which currently operate, and until the completion of the Marathon Oil acquisition will continue to operate, as independent public companies. There can be no assurances that our respective businesses can be integrated successfully. It is possible that the integration process could result in the loss of key employees from both companies; the loss of commercial and vendor partners; the disruption of our, Marathon Oil’s or both companies’ ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Marathon Oil acquisition, management attention and resources will be required to plan for such integration.
An inability to realize the full extent of the anticipated benefits of the Marathon Oil acquisition and the other transactions contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of the common stock of the combined company.
In addition, the actual integration may result in additional and unforeseen expenses, and the anticipated benefits of the integration plan may not be realized. There are a large number of processes, policies, procedures, operations and technologies and systems that must be integrated in connection with the Marathon Oil acquisition and the integration of Marathon Oil’s business. Although we expect that the elimination of duplicative costs, strategic benefits, and additional income, as well as the realization of other efficiencies related to the integration of the business, may offset incremental transaction and acquisition-related costs over time, any net benefit may not be achieved in the near term or at all. If we and Marathon Oil are not able to adequately address integration challenges, we may be unable to successfully integrate operations or realize the anticipated benefits of the integration of the two companies.
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, 2024
2,354,484
$
113.48
2,354,484
$
13,578
August 1 - 31, 2024
—
—
—
13,578
September 1 - 30, 2024
8,426,320
106.81
8,426,320
12,678
10,780,804
10,780,804
*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, 2024, we had repurchased $32.3 billion of shares. In October 2024, our Board of Directors approved an increase to our existing authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in the Marathon Oil transaction, such that the Company is not to exceed $65 billion in aggregate purchases. 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. In connection with the pending transaction with Marathon Oil, share repurchases were restricted for a period of time during 2024, pursuant to SEC regulations. These restrictions ended after the Marathon Oil stockholder approval on August 29, 2024, and share repurchases were subsequently resumed. See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2023 Annual Report on Form 10-K.
Item 5. Other Information
Insider Trading Arrangements
During the three-month period ended September 30, 2024, no officer or director of the company adopted or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement.
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.
