CONOCOPHILLIPS (COP)

Item 7.    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 and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. 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 65.

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 both production and reserves with operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2024, we employed approximately 11,800 people worldwide and had total assets of $123 billion.

Completed Acquisition of Marathon Oil Corporation

On November 22, 2024, we completed our acquisition of Marathon Oil, an independent oil and gas exploration and production company. The acquisition adds high-quality, low cost of supply, development opportunities to our existing Lower 48 portfolio and additional LNG capacity to our global LNG portfolio through Equatorial Guinea.

At closing, the acquisition was valued at approximately $16.5 billion, in which 0.255 shares of ConocoPhillips common stock was exchanged for each outstanding share of Marathon Oil common stock, resulting in the issuance of approximately 143 million shares of ConocoPhillips common stock. We also assumed $4.6 billion in aggregate principal amount of outstanding debt for Marathon Oil, which was recorded at fair value of $4.7 billion as of the closing date. We expect to capture approximately $1 billion in synergies on a run rate basis within the first full year following the close of the transaction. See Note 3 and Note 8.

Overview

At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.

The macro-environment of the global energy industry continues to evolve. We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets. We call this our Triple Mandate, and it represents our commitment to create long-term value for stockholders. Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.

Total company production in 2024 was 1,987 MBOED, yielding cash provided by operating activities of $20.1 billion. We invested $12.1 billion into the business in the form of capital expenditures and investments, inclusive of $0.4 billion of spend related to fourth-quarter acquisitions, and provided returns of capital to shareholders of $9.1 billion through our ordinary dividend, VROC and share repurchases. In 2024, we returned $3.6 billion through the ordinary dividend and VROC, including in December when we increased our ordinary dividend by 34 percent to 78 cents per share, effectively incorporating the amount of the prior quarter VROC into the ordinary dividend. In addition, we returned $5.5 billion to shareholders through share repurchases. As of December 31, 2024, we have repurchased $34.3 billion of our authorized share repurchase program since 2016. In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework. We also declared a first-quarter ordinary dividend of 78 cents per share.

In 2024, we continued to optimize our portfolio geared towards our return focused value proposition. In the third quarter, we added to our global LNG portfolio through agreements that provide additional access to European and Asian natural gas markets by entering into an 18-year agreement securing regasification capacity at Zeebrugge LNG terminal in Belgium which includes regasification services for approximately 0.75 MTPA of LNG beginning in 2027. Additionally, in the third quarter, we entered into a long-term LNG sales agreement for approximately 0.5 MTPA into Asia starting in 2027.

After exercising our preferential rights, we completed our acquisition of additional working interest in the Kuparuk River Unit and Prudhoe Bay Unit in our Alaska segment in the fourth quarter of 2024. In conjunction with the announcement of our acquisition of Marathon Oil, we communicated a disposition target of approximately $2 billion of assets across the portfolio. We recently entered into agreements to sell noncore assets within our Lower 48 segments that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments. See Note 3.

In the fourth quarter of 2024, we completed strategic debt transactions, which simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 3 and Note 8.

Operationally, we remain focused on safely executing the business. Production for 2024 was 1,987 MBOED, representing an increase of 161 MBOED or nine percent compared to 2023. After adjusting for closed acquisitions and dispositions, production increased by 69 MBOED or three percent. Our Lower 48 segment achieved record production of 1,152 MBOED in 2024. Our international projects reached several key operational milestones; including first production ahead of schedule at Eldfisk North in Norway, Nuna in Alaska and Bohai Bay in China; and we celebrated the one thousandth cargo lift at both APLNG and Bohai Bay in China.

Business Environment

The energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. Our profitability, reserves base, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our foundational principles guide our differential value proposition to deliver competitive returns on and of capital 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, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.

Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2024. In 2024, we initiated and completed strategic debt transactions to extend the weighted average maturity of our portfolio and reduce near-term debt maturities. We ended the year with cash and cash equivalents and restricted cash of $5.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion, maintaining balance sheet strength.

Peer leading distributions. We believe in delivering value to our shareholders via our return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and the discretion to utilize VROC in an elevated price environment. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2024, we returned $3.6 billion to shareholders through our ordinary dividend and VROC and $5.5 billion through share repurchases. Our combined dividends and share repurchases of $9.1 billion represented 45 percent of our net cash provided by operating activities. In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework.

Disciplined investments. Our goal is to optimize free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.

•Exercise capital discipline. Our global portfolio is deep, diverse and durable. As we consider our capital investment opportunities, we apply a rigorous framework that we believe allows for competitive free cash flow to be available to return to shareholders. By allocating to our low cost of supply resource base, we are allocating to high return assets and driving resiliency to low prices. We also balance our investments between short and longer cycle projects. For example, in 2024, we invested in short-cycle projects in the Lower 48 segment, as well as longer-cycle projects such as Willow in Alaska and LNG projects in Qatar and Port Arthur. This capital allocation framework seeks to maximize free cash flow through price cycles. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A.

•Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis and report to management. Managing costs is critical to maintaining a competitive position in our cyclical industry and positively impacts our ability to deliver strong cash from operations.

•Optimize our portfolio. We continue to evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2024, we completed our acquisition of Marathon Oil and additional working interest in Alaska, as well as signed additional LNG regasification and sales agreements. In 2024, we also signed an agreement to divest certain noncore assets in our Lower 48 segment. See Note 3.

•Add to our proved reserve base. We primarily add to our proved reserve base in three ways:

•Acquire interests in existing or new fields.

•Apply new technologies and processes to improve recovery from existing fields.

•Successfully explore, develop and exploit new and existing fields.

Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. Our reserve replacement was 244 percent in 2024, reflecting a net increase from development drilling activity; extensions and discoveries; and purchases, including our acquisition of Marathon Oil; partially offset by lower prices. Our organic reserve replacement, which excludes a net increase of 886 MMBOE from sales and purchases, was 123 percent in 2024.

In the three years ended December 31, 2024, our reserve replacement was 183 percent. Our organic         reserve replacement during the three years ended December 31, 2024, which excludes a net increase of 1,064 MMBOE related to sales and purchases, was 131 percent.

See "Supplementary Data - Oil and Gas Operations" for more information.

Environmental, Social and Governance performance. We are committed to the efficient and effective exploration and production of oil and natural gas. We seek to deliver energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process and remain committed to our targets. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors to executive leadership and business unit managers.

For more information on our commitment to responsible and reliable ESG performance, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.

Commodity Prices

Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but 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. The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2022:

Brent crude oil prices decreased two percent from $82.62 per barrel in 2023 to $80.76 per barrel in 2024. Similarly, average WTI crude oil prices decreased two percent from $77.62 per barrel in 2023 to $75.72 per barrel in 2024. Prices were lower through 2024 due to slower global demand growth in 2024 relative to 2023 and higher supplies from non-OPEC Plus counties.

U.S. Henry Hub natural gas prices decreased 17 percent from an average of $2.74 per MMBTU in 2023 to $2.27 per MMBTU in 2024. Natural gas prices decreased due to excess North American natural gas storage levels following a mild 2023-2024 winter. Lower 48 segment realized gas prices decreased to $0.18 in the third quarter of 2024 driven by lower regional prices related to pipeline capacity constraints. In the fourth quarter of 2024 prices increased as constraints were relieved and realizations ended the year at an average of $0.87.

Our realized bitumen price increased 14 percent from an average of $42.15 per barrel in 2023 to $47.92 per barrel in 2024. The increase was driven by narrowing WCS differentials due to Trans Mountain Expansion project egress, tightening Russian sanctions impacting global heavy oil supply and improving heavy oil demand in Asia. We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies.

Our worldwide annual average realized price decreased six percent from $58.39 per BOE in 2023 to $54.83 per BOE in 2024 primarily due to lower crude and natural gas prices.

Key Operating and Financial Summary

Significant items during 2024 and recent announcements included the following:

•Completed the acquisition of Marathon Oil, adding high-quality, low cost of supply inventory adjacent to the company's leading U.S. unconventional position;

•Reported fourth-quarter 2024 earnings per share of $1.90;

•Delivered 2024 reserve replacement ratio of 244 percent and organic reserve replacement ratio of 123 percent;

•Announced planned 2025 return of capital target of $10 billion at current commodity prices and declared first-quarter 2025 ordinary dividend of $0.78 per share;

•Provided 2025 guidance including full-year capital of approximately $12.9 billion;

•Generated cash provided by operating activities of $20.1 billion;

•Distributed $9.1 billion to shareholders, including $5.5 billion through share repurchases and $3.6 billion through the ordinary dividend and VROC;

•Ended the year with cash, cash equivalents and restricted cash of $5.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion;

•Advanced previously announced $2 billion disposition target by signing agreements to divest noncore Lower 48 assets of $0.6 billion, subject to customary closing adjustments and expected to close in the first half of 2025;

•Delivered full-year total company and Lower 48 production of 1,987 MBOED and 1,152 MBOED, respectively. Excluding one month of Marathon Oil production, the company and Lower 48 produced 1,955 MBOED and 1,124 MBOED, respectively;

•Reached first production at Nuna in Alaska and Bohai Phase 5 in China in the fourth quarter and at Eldfisk North in Norway in the second quarter;

•Progressed global LNG strategy with a long-term regasification agreement at Zeebrugge LNG terminal in Belgium and a long-term sales agreement in Asia;

•Exercised preferential rights and acquired additional working interests in Alaska's Kuparuk River and Prudhoe Bay Units in the fourth quarter;

•Completed debt transactions to simplify the company's capital structure post the acquisition of Marathon Oil, extending the weighted average maturity and improving the weighted average coupon of the portfolio; and

•Achieved the Oil and Gas Methane Partnership 2.0 Gold Standard designation in 2024.

Outlook

Production, DD&A and Capital

2025 production guidance is 2.34 to 2.38 MMBOED which includes 20 MBOED from planned turnarounds. First-quarter 2025 production is expected to be 2.34 to 2.38 MMBOED, which includes impacts of 20 MBOED from January weather and 5 MBOED from turnarounds.

Guidance for 2025 includes DD&A of $11.3 to $11.5 billion and capital expenditures of approximately $12.9 billion.

Operating Segments

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; 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.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons between 2024 and 2023. For discussion of year-to-year comparisons between 2023 and 2022, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2023 10-K.

Consolidated Results

Summary Operating Statistics

Total Company Production

We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2024, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar, Libya and Equatorial Guinea.

Total production of 1,987 MBOED increased 161 MBOED or nine percent in 2024 compared with 2023. Production increases include:

•New wells online in the Lower 48, Alaska, Australia, Canada, China, Libya and Norway.

•Our acquisition of the remaining working interest in Surmont in the fourth quarter of 2023.

•Our acquisition of Marathon Oil in the fourth quarter of 2024.

The increase in production during 2024 was partly offset by normal field decline.

After adjusting for closed acquisitions and dispositions, production increased by 69 MBOED or three percent.

Income Statement Analysis

Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

Below is select financial data provided on a consolidated basis. The full Income Statement can be found in Item 8. Financial Statements and Supplementary Data.

Sales and other operating revenues decreased $1,396 million in 2024, primarily due to lower realized natural gas and crude prices of $1,031 million and $791 million, respectively, and the timing of sales as compared to 2023. These decreases were partially offset by higher volumes of $2,659 million, inclusive of sales volumes from our acquisitions of Surmont and Marathon Oil, and higher realized bitumen prices of $258 million. See Note 3.

Gain (loss) on dispositions decreased $177 million in 2024, primarily due to the absence of gains associated with the divestitures of an equity investment and noncore assets in Lower 48 segment.

Purchased commodities decreased $1,963 million in 2024, primarily driven by lower natural gas and crude prices, partially offset by higher crude volumes.

Production and operating expenses increased $1,058 million in 2024, due to higher lease operating expenses and transportation costs 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. See Note 3.

Selling, general and administrative expenses increased $453 million in 2024, primarily due to transaction expenses of $545 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs. See Note 15.

DD&A increased $1,329 million in 2024 primarily due to higher volumes in our Lower 48 and Canada segments, higher rates in our Alaska and Lower 48 segments and the impact of our acquisition of Marathon Oil. See Note 3.

Foreign currency transaction (gain) loss for the year was improved by $142 million, primarily due to the absence of losses of $112 million associated with forward contracts in support of our Surmont acquisition. See Note 3.

Other expenses increased $179 million primarily related to a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 8.

See Note 16—Income Taxes for information regarding our income tax provision and effective tax rate.

Segment Results

Unless otherwise indicated, discussion of Segment Results is after-tax.

A summary of the company’s net income (loss) by business segment follows:

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

Alaska

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 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 $1,326 million in 2024, compared with earnings of $1,778 million in 2023.

Decreases to earnings included lower revenues resulting from lower commodity prices of $73 million and the timing of sales as compared with 2023. Additional decreases to earnings included higher DD&A expenses of $175 million, driven by higher rates as a result of 2023 year-end downward reserve revisions as well as higher production and operating expenses of $90 million, driven by higher well work activity of $56 million and transportation related costs of $26 million.

Production

Average production decreased one MBOED in 2024 compared with 2023, primarily due to normal field decline.

The production decrease was partly offset by new wells online at our Western North Slope and Greater Kuparuk Area assets.

Acquisition of Additional Working Interest in Kuparuk River Unit and Prudhoe Bay Unit

After exercising our preferential rights, we completed an acquisition of additional working interest in both the Kuparuk River Unit and the Prudhoe Bay Unit in the fourth quarter of 2024. Production from the additional working interest averaged approximately five MBOED each month for November and December 2024. See Note 3.

Lower 48

The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 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 $5,175 million in 2024, compared with earnings of $6,461 million in 2023.

Decreases to earnings included lower revenues resulting from lower overall commodity prices of $904 million and the timing of sales as compared with 2023, partly offset by higher volumes of $1,003 million, which includes volumes added from our acquisition of Marathon Oil. Additional decreases to earnings included higher DD&A of $562 million, driven by higher production of $250 million, higher rates of $181 million and impacts from our acquisition of Marathon Oil of $139 million; higher production and operating expenses of $431 million, driven by higher transportation related costs of $132 million, expenses associated with our acquisition of Marathon Oil of $110 million and higher lease operating expenses of $100 million; as well as the absence of gains associated with the divestiture of an equity investment of $100 million. See Note 3.

Production

Total average production increased 85 MBOED in 2024 compared with 2023, primarily due to new wells online from our development programs in Delaware Basin, Eagle Ford, Midland Basin and Bakken and the impact from assets acquired from Marathon Oil. See Note 3.

The production increase was partly offset by normal field decline and higher unplanned downtime across all basins.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil. The transaction added additional assets to our Lower 48 segment across several basins. Production from Lower 48 assets acquired from Marathon Oil averaged approximately 334 MBOED in the month of December 2024. See Note 3.

Planned Dispositions

We recently entered into agreements to sell noncore assets within our Lower 48 segment that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments. See Note 3.

Canada

*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. In 2024, Canada contributed ten percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Canada reported earnings of $712 million in 2024 compared with earnings of $402 million in 2023.

Earnings included higher revenues resulting from higher volumes of $676 million; driven by our increased working interest in Surmont of $584 million and new wells online in the Montney of $180 million, partially offset by planned turnaround activity at Surmont impacting revenues by $157 million. Additionally, revenues increased from higher overall commodity prices of $153 million, driven primarily by higher bitumen prices. See Note 3.

Decreases to earnings included higher production and operating expenses of $215 million; driven by an impact of $175 million related to higher overall production, including our increased working interest in Surmont; as well as expenses of $55 million related to turnaround activity at Surmont. Additional decreases to earnings included higher DD&A expenses of $166 million resulting from higher volumes and the absence of a $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit in 2023.

Production

Total average production increased 60 MBOED in 2024 compared with 2023. 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.

These production increases were partly offset by higher downtime resulting from a planned turnaround activity at a Surmont central processing facility and normal field decline.

Europe, Middle East and North Africa

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K. In 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)

The Europe, Middle East and North Africa segment reported earnings of $1,189 million in 2024 compared with earnings of $1,189 million in 2023.

Earnings in 2024 included lower revenues resulting from lower overall commodity prices of $118 million and the timing of sales as compared with 2023, partly offset by higher volumes of $144 million, which includes $49 million from volumes added from our acquisition of Marathon Oil. Additional decreases to earnings included higher DD&A of $51 million.

Consolidated Production

Average consolidated production increased 16 MBOED in 2024, compared with 2023. The consolidated production increase was primarily due to new wells online and improved performance in Norway, as well as the impact from assets acquired from Marathon Oil. See Note 3.

The production increase was partly offset by normal field decline.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil. The transaction added Equatorial Guinea to our global portfolio which resides in our Europe, Middle East and North Africa segment. Production from Equatorial Guinea averaged approximately 40 MBOED in the month of December 2024. See Note 3.

Exploration Activity

In 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. See Note 6.

Asia Pacific

The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 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 $1,724 million in 2024, compared with $1,961 million in 2023.

Decreases to earnings included lower revenues resulting from lower commodity prices of $49 million and lower volumes of $20 million. Additional decreases to earnings included the absence of a tax benefit recognized in 2023 from the reversal of a tax reserve. See Note 16. Earnings also decreased due to lower equity in earnings of affiliates of $57 million.

Increases to earnings included lower DD&A expenses of $27 million resulting from lower volumes.

Consolidated Production

Average consolidated production decreased one MBOED in 2024, compared with 2023. The decrease was primarily due to normal field decline.

These production decreases were partly offset by development activity at Bohai Bay in China.

Other International

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

Earnings from our Other International operations improved $12 million in 2024, compared with 2023.

Corporate and Other

Net interest consists of interest and financing expense, net of interest income and capitalized interest.

Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $359 million in 2024 compared with 2023, primarily due to transaction expenses of $432 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs. See Note 15.

Technology includes our investments in low-carbon technology opportunities as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG 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 decreased due to increased costs in low-carbon and other new technologies and lower licensing revenues.

Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in “Other” increased by $422 million in 2024 compared with 2023. This was primarily due to a tax benefit of $455 million as a result of the acquisition of Marathon Oil and the subsequent utilization of foreign tax credits, and the absence of $89 million loss associated with forward foreign exchange contracts to buy CAD, in support of our acquisition of additional working interest in Surmont in 2023. Decreases to earnings in "Other" were driven by a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024. See Note 3, Note 8 and Note 16.

Capital Resources and Liquidity

Financial Indicators

Balance Sheet related line items are shown as of December 31st.

*Capital includes total debt and total equity.

To meet our short- 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. In 2024, the primary uses of our available cash were $12.1 billion to support our ongoing capital expenditures and investments program, which included $0.4 billion of spend related to fourth-quarter acquisitions; $5.5 billion to repurchase common stock; and $3.6 billion to pay the ordinary dividend and VROC. In addition to cash from operating activities, the other primary sources of capital were $5.6 billion in proceeds from long-term debt issuances, of which $4.1 billion was used to repurchase certain existing Marathon Oil debt assumed in the acquisition and ConocoPhillips debt; and $0.4 billion net sales of short-term investments. In 2024, cash and cash equivalents remained flat with 2023 at $5.6 billion. See Note 8.

At December 31, 2024, we had cash and cash equivalents of $5.6 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $11.6 billion of liquidity. We believe current cash balances and cash generated by operations, 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, capital return program and required debt payments.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities in 2024 totaled $20.1 billion, compared with $20.0 billion for 2023, and $28.3 billion for 2022. In 2024, cash provided by operating activities improved from 2023 due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024. The increase in production was partly offset by lower commodity prices and lower distributions from equity affiliates. See Note 3.

The decrease in cash provided by operating activities from 2023 compared to 2022 is primarily due to lower realized commodity prices across all products, partly offset by higher sales volumes, net of associated production and operating costs.

Our short- 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 absolute production volumes, as well as product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 1,987 MBOED in 2024, an increase of 161 MBOED or nine percent compared to 2023. First-quarter 2025 production is expected to be 2.34 MMBOED to 2.38 MMBOED. 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; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices.

Investing Activities

In 2024, we invested $12.1 billion in capital expenditures and investments; $0.8 billion of which was primarily payments towards our equity investments in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4) and QatarEnergy LNG NFS(3) (NFS3); and $0.4 billion of spend related to fourth-quarter acquisitions. See Note 3. The remaining $10.9 billion funded our operating capital program. Capital expenditures invested in 2023 and 2022 were $11.2 billion and $10.2 billion, respectively. See the “Capital Expenditures and Investments” section.

In conjunction with the announcement of our acquisition of Marathon Oil, we communicated a disposition target of approximately $2 billion of assets across the portfolio. We recently entered into agreements to sell noncore assets within our Lower 48 segments that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments. See Note 3.

After exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A. Inc. and Union Oil Company of California in the fourth quarter of 2024 for $296 million before customary adjustments. See Note 3.

In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $2.7 billion of cash after customary adjustments. We funded this transaction by issuing new long-term debt. See Note 3 and Note 8.

Proceeds from asset sales were $0.3 billion in 2024, $0.6 billion in 2023 and $3.5 billion in 2022. In 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of Cenovus Energy (CVE), proceeds of approximately $1.5 billion, primarily from asset divestitures in our Asia Pacific and Lower 48 segments, and $0.5 billion in contingent payments associated with prior divestitures. See Note 3 and Note 5.

We invest in short-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Funds for short-term investments needs to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities within the 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. See Note 11 and Note 19.

Investing activities in 2024 included net sales of $415 million of investments. We had net sales of $961 million of short-term investments and net purchases of $546 million of long-term investments. See Note 18.

Financing Activities

In November 2024, we acquired Marathon Oil. At closing, the acquisition was valued at $16.5 billion and was allocated to assets acquired and liabilities assumed. ConocoPhillips common stock was issued and exchanged for outstanding Marathon Oil shares. With the acquisition, we also assumed Marathon Oil's debt of approximately $4.6 billion. See Note 3 and Note 8.

Our debt balance at December 31, 2024 was $24.3 billion compared with $18.9 billion at December 31, 2023. The current portion of debt, including payments for finance leases, is $1.0 billion. In 2024, the company retired $726 million principal amount of Notes at maturity consisting of $265 million of our 3.35% Notes and $461 million of our 2.125% Notes. In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion; a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt (with priority for Marathon Oil debt assumed); a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt; and remarketing of $0.4 billion in available municipal bonds. The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 8.

In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities. See Note 8.

In 2022, we repurchased notes, retired floating rate debt and executed a debt refinancing comprised of concurrent transactions including new debt issuances, a cash tender offer and debt exchange offers. In aggregate, these transactions along with naturally maturing debt, reduced the company's total debt by $3.3 billion.

In 2022, we refinanced our revolving credit facility from a total aggregate principal amount of $6.0 billion to $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 agreement calls for commitment fees on available, but unused, amounts. The 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 ConocoPhillips Company’s ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. 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 December 31, 2024.

In November 2024, Fitch affirmed our long-term credit rating. The current credit ratings on our long-term debt are:

•Fitch: “A” with a “stable” outlook

•S&P: “A-” with a “stable” outlook

•Moody's: "A2" with a "stable" outlook

See Note 8 for additional information on debt and the revolving credit facility.

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 rating 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.

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 December 31, 2024 and December 31, 2023, we had direct bank letters of credit of $278 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 amount of various types of debt and equity securities.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section.

Our debt balance at December 31, 2024, was $24.3 billion, an increase of $5.4 billion from the balance at December 31, 2023 of $18.9 billion. In 2024, the company assumed $4.6 billion principal of debt with our acquisition of Marathon Oil and retired $726 million principal amount of Notes at maturity. In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion; a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt; a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt; and the remarketing of $0.4 billion in available municipal bonds. The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities. See Note 8.

In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework. We plan to deliver a compelling, growing ordinary dividend and through-cycle share repurchases. We anticipate returning greater than 30 percent of cash from operating activities during periods where commodity prices are meaningfully higher than our planning price range. Our 2024 total capital returned was $9.1 billion.

In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases. In 2022, we executed concurrent debt refinancing transactions, repurchased existing notes, and retired floating rate notes upon natural maturity, that in aggregate reduced our total debt by $3.3 billion, while also lowering our annual cash interest expense and extending the weighted average maturity of our debt portfolio. See Note 8 for information regarding debt and Note 18 for information regarding non-cash consideration of the Surmont transaction.

Consistent with our commitment to deliver value to shareholders, for the full year of 2024, we paid ordinary dividends of $2.52 per common share and VROC payments of $0.60 per common share. In the fourth quarter of 2024, we incorporated the equivalent amount of prior quarter VROC into the ordinary dividend. In 2023 we paid ordinary dividends of $2.11 and VROC payments of $2.50 per common share and in 2022 we paid an ordinary dividend of $1.89 and VROC payments of $2.60. In February 2025, we declared a first-quarter ordinary dividend of $0.78 per common share payable March 3, 2025, to shareholders of record on February 17, 2025.

VROC remains a discretionary option in elevated price environments. The ordinary dividend and VROC are subject to numerous considerations and are determined and approved each quarter by the Board of Directors. Beginning in the first quarter of 2024, we announced and paid quarterly dividends and VROC payments concurrently. VROC payments had been paid in the subsequent quarter of announcement in 2023 and 2022.

In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase from our prior authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in our acquisition of Marathon Oil, such that the company is not to exceed $65 billion in aggregate repurchases. Share repurchases were $5.5 billion, $5.4 billion, and $9.3 billion in 2024, 2023, and 2022, respectively. As of December 31, 2024, share repurchases since the inception of our current program totaled 432.6 million shares and $34.3 billion since 2016. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors.

For more information on factors considered when determining the levels of returns of capital see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

As of December 31, 2024, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $31.6 billion. We expect to fulfill $7.5 billion of these obligations in 2025. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations of $13.0 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase obligations of $16.8 billion are related to market-based contracts for commodity product purchases with third parties. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

Capital Expenditures and Investments

* Excludes capital related to acquisitions of businesses, net of cash acquired.

Our capital expenditures and investments for the three-year period ended December 31, 2024, totaled $33.5 billion. The 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.

2025 Capital Budget

In February 2025, we announced our 2025 operating plan capital is expected to be $12.9 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.

Guarantor Summarized Financial Information

We have various cross guarantees among 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 this presentation.

Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented separately below:

Summarized Income Statement Data

*Includes approximately $8.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

Contingencies

We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See “Critical Accounting Estimates” and Note 10 for information on contingencies.

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. See Note 16.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:

•U.S. Federal Clean Air Act, which governs air emissions;

•U.S. Federal Clean Water Act, which governs discharges to water bodies;

•EU Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH);

•U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;

•U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;

•U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;

•U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;

•U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; and

•EU Trading Directive resulting in EU Emissions Trading Scheme (EU ETS).

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada.

An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their equivalents in their respective jurisdictions. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

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 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 December 31, 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 most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $914 million in 2024 and are expected to be approximately $1.1 billion in 2025 and 2026. Capitalized environmental costs were $535 million in 2024 and are expected to be about $720 million and $656 million in 2025 and 2026, respectively.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2024, our balance sheet included total accrued environmental costs of $206 million, compared with $184 million at December 31, 2023, for remediation activities in the U.S. and Canada. 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 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 and Note 10 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 focusing on GHG emissions reduction. These laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our operational results and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include:

Emissions trading schemes.

•EU ETS is the program through which many of the EU member states aim to reduce emissions. Our cost of compliance with the EU ETS in 2024 was approximately $20 million (net share before-tax).

•The U.K. Emissions Trading Scheme (U.K. ETS) is the program with which the U.K. has replaced the EU ETS. Our cost of compliance with the U.K. ETS in 2024 was approximately $0.8 million (net share before-tax).

GHG regulations for emissions reductions.

•The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. The total cost of compliance related to this regulation in 2024 was approximately $4.5 million (net share before-tax) after savings from using our existing bank of offsets and performance credits ($7.7 million before savings).

•As of April 2024, the British Columbia Output Based Pricing System (BC OBPS) regulation requires facilities or linear operations (such as oil and gas gathering systems) with emissions equal to or greater than 10,000 metric tonnes of carbon dioxide or equivalent per year to remit payments on the difference between actual emissions and allowable emissions based on product and activity benchmarks. The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments are not due until later in 2025. Based on interim benchmarks, our BC OBPS obligation is expected to total $1.5 million (net share before-tax) for Montney in 2024.

•In 2024, the EU passed regulation on the reduction of methane emissions in the energy sector that will apply a methane limit on oil and gas imports to the EU, as well as mandate the monitoring, reporting, verification and reduction of methane emissions.

•Our APLNG assets in Australia are subject to the Safeguard Mechanism, enacted through the National Greenhouse and Energy Reporting Act 2007. In the previous Australian financial year of July 1, 2023, to June 30, 2024, our operated downstream APLNG facility was in excess of its baseline emissions, while the upstream partner-operated facilities were below their baseline emissions. As we expect there to be a surplus of eligible carbon units across the joint venture, there is no expense expected to be incurred by ConocoPhillips for the 2024 Australian financial year.

•In 2024 the U.S. EPA published final rulemaking for New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc). Implementing this regulation across our U.S. portfolio will result in additional compliance costs.

•In connection with OOOOb and OOOOc rulemaking, the U.S. EPA established the Methane Super Emitter Program whereby certified third parties can use EPA-approved technology to identify and report super-emitter events for EPA review. An operator must initiate an investigation within five days of receiving notification from the EPA regarding a super-emitter event.

•In November 2024, the U.S. EPA finalized the Waste Emissions Charge (WEC) as part of the Methane Emission Reduction Program (MERP) within the Inflation Reduction Act of 2022. The implementation of the WEC will require payments to the EPA, accounting for methane emissions subject to the rule. The filing deadline for the 2024 WEC is August 2025.

Carbon taxes in certain jurisdictions.

•We incurred carbon tax cost in our Montney operations in the first three months of 2024, before the BC OBPS came into force. We may also incur a carbon tax for any emissions in Montney that falls outside the scope of our BC OBPS activities. We also incur a nominal carbon tax for emissions from fossil fuel combustion at some of our Surmont operations in Alberta that occur outside of TIER facilities. Carbon tax costs in our Canada operations totaled $1.7 million (net share before-tax).

•Our cost of compliance with Norwegian carbon legislation in 2024 was approximately $37 million (net share before-tax).

Other environmental regulations.

•The White House Council on Environmental Quality (CEQ) issued final National Environmental Policy Act implementation regulations (NEPA Phase 2) in 2024. Since then, the DC Circuit Court has suggested that CEQ lacks authority to adopt any binding regulations, introducing potential uncertainty into the regulatory process.

•Climate Superfund laws. In 2024, New York and Vermont passed legislation seeking to hold certain energy companies financially responsible for state climate change mitigation and adaptation measures, following the “polluter pays” model of existing Superfund laws. This responsibility may include paying into a fund for infrastructure repairs and recovery from extreme weather events that would otherwise be covered by the government. While only two U.S. states have enacted such laws to date, it is likely that more states will consider a similar approach. Compliance with such legislation may expose us to significant additional liabilities.

•Climate Private Action laws. In 2025, California, New Hampshire, and Oregon introduced bills seeking to create a private right of action for individuals to bring strict liability claims for alleged damages related to climate change impacts (including non-economic, actual and punitive damages). These bills also authorize insurance companies to pursue subrogation claims to recover damages for amounts paid to insureds for climate change impacts.

Non-regulatory initiatives or agreements.

•The U.S. government announced on September 17, 2021 the Global Methane Pledge, a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.

•The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change set out a process for achieving global emissions reductions. Accordingly, parties to the Paris Agreement have set targets to reduce emissions by 2030. While the current administration has officially withdrawn the U.S. from the Paris Agreement, some states have indicated that they plan to remain committed to the goals of the agreement.

Regulated sustainability disclosures.

Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement. In March 2022 the U.S. SEC proposed rule changes that would require registrants to include certain climate-related disclosures in their registration statements and periodic reports; In January 2023 the EU finalized the Corporate Sustainability Reporting Directive that will require more detailed sustainability reporting; in June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state; and in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures.

Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:

•Whether and to what extent legislation or regulation is enacted;

•The timing of the introduction of such legislation or regulation;

•The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation;

•The price placed on GHG emissions (either by the market or through a tax);

•The GHG emissions reductions required;

•The price and availability of offsets;

•The amount and allocation of allowances;

•Technological and scientific developments leading to new products or services;

•Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature); and

•Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

See 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 Note 10 for information on climate change litigation.

Company Response to Climate-Related Risks

The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, 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.

Our Climate Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our previously established emissions-reduction targets. First, meeting global energy demand requires a focus on delivering production that will best compete in any energy mix scenario. This production will be delivered from resources with a competitive cost of supply and low GHG intensity, as well as portfolio diversity by market and asset type. Next, in delivering competitive returns, ConocoPhillips has been a leader in shifting the exploration and production sector’s value proposition away from one focused on production toward one focused on returns. Finally, to drive accountability for the emissions that are within our control, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.

Key elements of the Climate Risk Strategy include:

•Strategic flexibility and portfolio composition

◦Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet global 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.

◦Testing our portfolio against future energy demand scenarios through a comprehensive scenario planning process that helps us assess the resilience of our corporate strategy to climate risk.

•Scope 1 and 2 emissions targets and reductions

◦Setting targets for emissions over which we have ownership and control.

◦Reducing emissions through the marginal abatement cost curve process.

•LNG and technology

◦Building an attractive LNG portfolio as an important component of responsibly meeting global energy demand due to LNG's opportunity to displace higher-emissions fuels such as coal for electricity generation.

◦Evaluating potential investments in emerging alternative energy sources and low-carbon technologies.

•External engagement

◦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.

Our Climate Risk Strategy does not include a Scope 3 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 federal regulation of methane.

In support of addressing our Scope 1 and 2 emissions, we have made recent progress in several key areas.

•Completed our 2024 scope 1 and 2 emissions reduction projects within the allotted capital and cost budget. These projects will support our GHG emissions intensity reduction target of 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.

•Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative, one of only three U.S. companies to earn this distinction.

•Remained on schedule to meet a target of zero routine flaring by the end of 2025 for heritage ConocoPhillips assets.

Our emissions reduction efforts are supported by our multi-disciplinary Low Carbon Technologies organization. See Item 1A. Risk Factors—Our ability to successfully execute on our plans to reduce our operational GHG emissions intensity is subject to a number of risks and uncertainties, and such reductions may be costly and challenging to achieve.

New Accounting Standards

For discussion of new accounting standards, see Note 24.

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1 for descriptions of our significant accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been recognized.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.

At year-end 2024, we held $14.7 billion of net capitalized unproved property costs, $10.8 billion of which was added this year through our acquisition of Marathon Oil. These capitalized costs consist primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $13.4 billion is concentrated in the Lower 48 Basins, primarily the Delaware, Eagle Ford and Bakken Basins, where we have an ongoing significant and active development program. Outside of the Lower 48 Basins, the remaining $1.3 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development.

If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.

At year-end 2024, total suspended well costs were $196 million, compared with $184 million at year-end 2023. For additional information on suspended wells, including an aging analysis, see Note 6.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our geosciences and reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates. See “Supplementary Data - Oil and Gas Operations” for additional information.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to PSCs, reported under the “economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. We would expect reserves from these contracts to decrease when product prices rise and increase when prices decline.

The estimation of proved reserves is also important to the income statement because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2024, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $77 billion and the DD&A recorded on these assets in 2024 was approximately $9.4 billion. The estimated proved developed reserves for our consolidated operations were 4.4 billion BOE at the end of 2023 and 5.1 billion BOE at the end of 2024. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2024 would have increased by an estimated $1,040 million.

Business Combination—Valuation of Oil and Gas Properties

For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 – “Business Combinations” and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates.

Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate is recorded. Subsequent to the acquisition date, and not later than one year from the acquisition date, we record any material adjustments to the initial estimate based on new information obtained that would have existed as of the date of the acquisition. Any adjustment that arises from information obtained that did not exist as of the date of acquisition is recorded in the period the adjustment arises. See Note 3.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the periods in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period.

Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. Since quoted market prices are usually not available, the fair value is typically based on the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change between the time of initial recognition of the liability and future settlement of our obligation.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they 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. See Note 7.

Projected Benefit Obligations

The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by $500 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount rate assumption would increase annual benefit expense by $40 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual benefit expense by $70 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a significant reduction in the expected years of future service of present employees or the elimination of the accrual of defined benefits for some or all of their future services for a significant number of employees, we could recognize a curtailment gain or loss. See Note 15.

Contingencies

A number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages and underpayments associated with environmental remediation, tax, contracts and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure; however, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and Note 10.

Income Taxes

We are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weigh the evidence based on objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing oil and gas prices). See Note 16.

We regularly assess and, if required, establish accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit from an uncertain tax position when it is more likely than not the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note 16.

Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, the anticipated benefits of our acquisition of Marathon Oil, the anticipated impact of our acquisition of Marathon Oil on the combined company’s business and future financial and operating results and the expected amount and timing of synergies from our acquisition of Marathon Oil are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning development or replacement of reserves and future dividends. You can often identify our forward-looking statements by the words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.

We based 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 or inaccurate, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:

•Effects of volatile commodity prices, including prolonged periods of low commodity prices, which may adversely impact our operating results and our ability to execute on our strategy and could result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.

•Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict; security threats on facilities and infrastructure; global health crises; the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries; or the resulting company or third-party actions in response to such changes.

•The potential for insufficient liquidity or other factors, such as those described herein, that could impact our ability to repurchase shares and declare and pay dividends, whether fixed or variable.

•Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

•Reductions in our reserve replacement rates, whether as a result of significant declines in commodity prices or otherwise.

•Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

•Failure to progress or complete announced and future development plans related to constructing, modifying or operating E&P and LNG facilities, or unexpected changes in costs, inflationary pressures or technical equipment related to such plans.

•Significant operational or investment changes imposed by legislative and regulatory initiatives and international agreements addressing environmental concerns, including initiatives addressing the impact of global climate change, such as limiting or reducing GHG emissions; regulations concerning hydraulic fracturing, methane emissions, flaring or water disposal; and prohibitions on commodity exports.

•Broader societal attention to and efforts to address climate change may cause substantial investment in and increased adoption of competing or alternative energy sources.

•Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate Risk Strategy.

•Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.

•Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.

•Potential disruption or interruption of our operations and any resulting consequences due to accidents; extraordinary weather events; supply chain disruptions; civil unrest; political events; war; terrorism; cybersecurity threats or information technology failures, constraints or disruptions.

•Liability for remedial actions, including removal and reclamation obligations, under existing or future environmental regulations and litigation.

•Liability resulting from pending or future litigation or our failure to comply with applicable laws and regulations.

•General domestic and international economic, political and diplomatic developments, including deterioration of international trade relationships; the imposition of trade restrictions or tariffs relating to commodities and material or products (such as aluminum and steel) used in the operation of our business; expropriation of assets; changes in governmental policies relating to commodity pricing, including the imposition of price caps; sanctions; or other adverse regulations or taxation policies.

•Competition and consolidation in the oil and gas E&P industry, including competition for sources of supply, services, personnel and equipment.

•Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment.

•Challenges or delays to our execution of, or successful implementation of the acquisition of Marathon Oil or any future asset dispositions or acquisitions we elect to pursue; potential disruption of our operations, including the diversion of management time and attention; our inability to realize anticipated cost savings or capital expenditure reductions; difficulties integrating acquired businesses and technologies; or other unanticipated changes.

•Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we anticipate, if at all.

•The operation, financing and management of risks of our joint ventures.

•The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.

•Uncertainty as to the long-term value of our common stock.

•The factors generally described in Part I—Item 1A in this 2024 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

Item 7.    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 and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. 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 65.

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 both 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 December 31, 2023, we employed approximately 9,900 people worldwide and had total assets of $96 billion.

Overview

At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices. As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, 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 achieving 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.

Total company production in 2023 was 1,826 MBOED, yielding cash provided by operating activities of $20 billion. We invested $11.2 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of approximately $11 billion through our ordinary dividend, share repurchases and our VROC. For 2023, we returned $2.6 billion from our ordinary dividend, which included an increase from 51 cents per share to 58 cents per share, effective in December. We also returned $3.0 billion to shareholders from the VROC in 2023. In total for 2023, we returned $5.4 billion to shareholders through share repurchases. As of December 31, 2023, we have repurchased $28.8 billion of the $45 billion authorized share repurchase program. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. We also declared a first quarter ordinary dividend of 58 cents per share and a VROC of 20 cents per share.

In March, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.

In October, we completed our acquisition of the remaining 50 percent working interest in Surmont, an asset in our Canada segment, for $2.7 billion of cash after customary adjustments. The transaction was funded by proceeds received via long-term debt offerings. This transaction includes a contingent payment arrangement of up to an additional $0.4 billion CAD (approximately $0.3 billion) over a five-year term. As the 100 percent owner and operator of Surmont, we will seek to optimize the asset while remaining on track to achieve our previously announced corporate emissions intensity objectives. See Note 3.

In 2023, we took several steps to further our global LNG business. In March, we completed our acquisition of 30 percent equity interest in PALNG Phase 1. In June, we completed our acquisition of a 25 percent equity interest in NFS3 in Qatar. Additionally, in June, we signed a 20-year offtake agreement at the Saguaro LNG export facility on the west coast of Mexico, subject to Mexico Pacific reaching FID and other certain conditions precedent. Furthermore, in September, we signed a 15-year throughput agreement securing regasification capacity at the Gate LNG terminal in the Netherlands. See Note 3.

In the second quarter of 2023, we completed a strategic debt refinancing that extends the weighted average maturity of our portfolio from 15 to 17 years and reduces near term debt maturities. See Note 9.

In April, we announced that we are accelerating our operations GHG emissions intensity reduction target through 2030. We are now targeting a reduction in gross operated and net equity operational emissions intensity of 50-60 percent from 2016 levels by 2030, an improvement from the previously announced target of 40-50 percent. In December, we achieved the Gold Standard Pathway in the Oil and Gas Methane Partnership (OGMP) 2.0 Initiative. For more information on our commitment to ESG and the Plan, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.

Operationally, we remain focused on safely executing the business. Our Lower 48 segment achieved record production in 2023. Our international projects reached several key operational milestones, including first production ahead of schedule at several subsea projects in Norway and China, as well as the startup of the second phase of Montney’s central processing facility in Canada. Production for 2023 was 1,826 MBOED, representing an increase of 88 MBOED or 5 percent compared to 2022. After adjusting for closed acquisitions and dispositions, production increased by 73 MBOED or 4 percent.

Key Operating and Financial Summary

Significant items during 2023 and recent announcements included the following:

•Generated cash provided by operating activities of $20.0 billion;

•Distributed $11.0 billion to shareholders through a three-tier framework, including $5.6 billion through the ordinary dividend and VROC and $5.4 billion through share repurchases;

•Ended the year with cash, cash equivalents, and restricted cash of $5.9 billion and short-term investments of $1.0 billion;

•Delivered record full-year total and Lower 48 segment production of 1,826 MBOED and 1,067 MBOED, respectively;

•Acquired the remaining 50 percent working interest in Surmont for approximately $2.7 billion as well as future contingent payments of up to $0.4 billion CAD ($0.3 billion);

•Took FID on the Willow project;

•Progressed global LNG strategy through expansion in Qatar, FID at PALNG and regasification agreements in the Netherlands and offtake agreements in Mexico;

•Reached first production at several subsea tiebacks in Norway, Surmont Pad 267 in Canada and Bohai Phase 4B in China;

•Commenced startup at the second phase of Montney's central processing facility in Canada;

•Awarded the Gold Standard Pathway designation by OGMP 2.0; and

•Accelerated the company's GHG emissions-intensity reduction target through 2030 from 40-50 percent to 50-60 percent, using a 2016 baseline.

Business Environment

The energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. For example, WTI crude oil prices averaged $78 per barrel in 2023, compared with $94 per barrel in 2022. Our profitability, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our Triple Mandate and foundational principles guide our differential value proposition to deliver competitive returns on and of capital 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, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.

•Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2023. In 2023, we initiated and completed a strategic debt refinancing to extend the weighted average maturity of our portfolio and reduced near-term debt maturities. In addition, we also funded the acquisition of the remaining 50 percent working interest in Surmont from the proceeds of new long-term debt issuances. We ended the year with cash and cash equivalents and restricted cash of $5.9 billion and short-term investments of $1.0 billion, maintaining balance sheet strength.

•Peer leading distributions. We believe in delivering value to our shareholders via our three-tiered return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and our VROC. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2023, we returned $5.6 billion to shareholders through our ordinary dividend and VROC and $5.4 billion through share repurchases. Our combined dividends and share repurchases of $11 billion represented over 50 percent of our net cash provided by operating activities. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain considerations.”

•Disciplined investments. Our goal is to achieve strong free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.

◦Exercise capital discipline. We participate in a commodity price-driven and capital-intensive industry, with varying lead times from when an investment decision is made to when an asset is operational and generates cash flow. As a result, we must invest significant capital to develop newly discovered fields, maintain existing fields and construct pipelines and LNG facilities. We allocate capital across a geographically diverse, low cost of supply resource base, which combined with legacy assets results in low overall production decline. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A. In setting our capital plans, we exercise a rigorous approach that evaluates projects using these cost of supply criteria, which we believe will lead to value maximization and cash flow expansion using an optimized investment pace, not production growth for growth’s sake. Our cash allocation priorities call for the investment of sufficient capital to sustain production and provide returns of capital to shareholders.

◦Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis and report to management. Managing costs is critical to maintaining a competitive position in our industry, particularly in a low commodity price environment, and positively impacts our ability to deliver strong cash from operations.

◦Optimize our portfolio. We continue to evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont and completed our acquisitions of equity interests in both the PALNG and NFS3 LNG projects and signed both LNG offtake and regasification agreements. See Note 3.

◦Add to our proved reserve base. We primarily add to our proved reserve base in three ways:

▪Acquire interest in existing or new fields.

▪Apply new technologies and processes to improve recovery from existing fields.

▪Successfully explore, develop and exploit new and existing fields.

As required by authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production, as shown in our supplemental reserve table disclosures. Our reserve replacement was 123 percent in 2023, reflecting a net increase from development drilling activity, extensions and discoveries and purchases, partially offset by lower prices. Our organic reserve replacement, which excludes a net increase of 184 MMBOE from sales and purchases, was 96 percent in 2023.

In the three years ended December 31, 2023, our reserve replacement was 219 percent. Our organic reserve replacement during the three years ended December 31, 2023, which excludes a net increase of 1,293 MMBOE related to sales and purchases, was 152 percent. See "Supplementary Data - Oil and Gas Operations" for more information.

Access to additional resources may become increasingly difficult as lower commodity price cycles can make projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations, national fiscal terms, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to fully replace our production over subsequent years.

See "Item 1A—Risk Factors - Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business."

•Environmental, Social and Governance performance. We seek to fulfill our mission of delivering energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors through to executive leadership and business unit managers.

In October 2020, we became the first U.S.-based oil and natural gas company to adopt a Paris-aligned climate risk framework that includes an ambition to achieve net-zero Scope 1 and 2 emissions on a gross operated and net equity basis by 2050. We believe that this framework, combined with our success in meeting the business objectives set by our Triple Mandate, represents the most effective way for us to sustainably contribute to society’s transition to a low-carbon economy. In 2023, we announced an acceleration of our operational GHG emissions intensity reduction target through 2030. In December, we achieved the Gold Standard Pathway in the OGMP 2.0 Initiative.

We believe that natural gas and oil will remain essential to the energy mix throughout the energy transition, and we also recognize the need for continuous reduction in the greenhouse gas intensity of production operations. The energy transition will likely be complex, evolving over multiple decades with many possible pathways and uncertainties. By following our Triple Mandate, we intend to meet this challenge in an economically viable, accountable and actionable way that creates long-term value for our stakeholders. For more information on our commitment to responsible and reliable ESG performance through the energy transition, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.

Commodity Prices

Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but 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. The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2021:

Brent crude oil prices averaged $82.62 per barrel in 2023, a decrease of 18 percent compared with $101.19 per barrel in 2022. Similarly, average WTI crude oil prices decreased 18 percent from $94.23 per barrel in 2022 to $77.62 per barrel in 2023. Prices were lower through 2023 as rising Non-OPEC supplies and Russia's ability to redirect crude oil to destinations outside the EU more than offset OPEC Plus crude oil supply curbs.

Henry Hub natural gas prices decreased 59 percent from an average of $6.65 per MMBTU in 2022 to $2.74 per MMBTU in 2023. Natural gas prices decreased due to mild winter weather and U.S. domestic supply growth outpacing demand growth.

Our realized bitumen price decreased 24 percent from an average of $55.56 per barrel in 2022 to $42.15 per barrel in 2023. The decrease was largely driven by weakness in WTI, reflective of global markets adjusting to new trade dynamics and global crude oil demand concerns. We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies.

Our worldwide annual average realized price decreased 27 percent from $79.82 per BOE in 2022 to $58.39 per BOE in 2023 primarily due to lower commodity prices.

Outlook

Production and Capital

2024 capital expenditure guidance is $11.0 to $11.5 billion.

2024 production guidance is 1.91 to 1.95 MMBOED. First-quarter 2024 production is expected to be 1.88 to 1.92 MMBOED.

Operating Segments

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; 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.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our operations, including commodity prices and production.

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons between 2023 and 2022. For discussion of year-to-year comparisons between 2022 and 2021, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2022 10-K.

Consolidated Results

A summary of the company’s net income (loss) by business segment follows:

Net Income (loss) decreased $7,723 million in 2023. Earnings were negatively impacted by:

•Lower realized commodity prices.

•Absence of a $462 million gain on disposition related to the divestiture of our Indonesia assets in the first quarter of 2022, contingent payments associated with a previous disposition in our Canada segment and lower contingent payments associated with a previous disposition in our Lower 48 segment. See Note 3.

•Higher DD&A expenses primarily due to higher rates from reserve revisions resulting from higher costs as well as higher overall production volumes.

•Higher production and operating expenses due to increased well work activities and higher volumes, primarily in the Lower 48 segment.

•Absence of a $515 million tax benefit recognized in 2022 related to the closing of an IRS audit. See Note 17.

•Lower equity in earnings of affiliates, primarily due to lower LNG sales prices.

•Absence of a gain of $251 million after-tax from the sale of our Cenovus Energy (CVE) common shares in 2022. See Note 5.

•Foreign currency transaction losses of $89 million arising from forward contracts in support of our Surmont acquisition and lower foreign currency remeasurement gains resulting from the USD strengthening against the NOK. See Note 3.

Earnings were positively impacted by:

•Higher sales volumes.

•Lower taxes other than income taxes primarily driven by lower commodity prices, partially offset by higher production volumes.

•Recognized foreign tax benefits. See Note 17.

•Commercial performance and timing.

•Higher interest income and lower interest expense due to higher capitalized interest for longer term major projects.

•Lower exploration expenses primarily related to the absence of an impairment of certain aged, suspended wells in our Canada segment and lower dry hole expenses across our portfolio. See Note 6.

Income Statement Analysis

Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

Sales and other operating revenues decreased $22,353 million in 2023, primarily due to lower realized commodity prices partially offset by higher sales volumes.

Equity in earnings of affiliates decreased $361 million in 2023, primarily due to lower earnings driven by lower LNG and crude prices. See Note 3.

Gain (loss) on dispositions decreased $849 million in 2023, primarily due to the absence of a gain of $534 million from the divestiture of our Indonesia assets, the absence of contingent payments associated with a previous disposition in our Canada segment and lower contingent payments associated with a previous disposition in our Lower 48 segment. See Note 3.

Other Income decreased $19 million in 2023 primarily due to the absence of a gain of $251 million after-tax from the sale of our Cenovus Energy (CVE) common shares in 2022, largely offset by higher interest income.

Purchased commodities decreased $11,996 million in 2023, primarily due to lower prices across all commodities.

Production and operating expenses increased $687 million in 2023, due to increased well work activities and higher production volumes, primarily in the Lower 48 segment.

Exploration expenses decreased $166 million in 2023, primarily due to the absence of an impairment of certain aged, suspended wells in our Canada segment as well as lower dry hole expenses. See Note 6.

DD&A increased $766 million in 2023 primarily due to higher rates from reserve revisions resulting from higher operating costs as well as higher overall production volumes primarily due to development in our Lower 48 segment.

Taxes other than income taxes decreased $1,290 million in 2023, caused primarily by lower commodity prices, partially offset by higher production volumes.

Foreign currency transaction (gain) loss for the year was impaired by $192 million, primarily as a result of losses of $112 million associated with forward contracts in support of our Surmont acquisition and lower foreign currency remeasurement gains resulting from the USD strengthening against the NOK. See Note 3.

See Note 17—Income Taxes for information regarding our income tax provision and effective tax rate.

Summary Operating Statistics

We explore for, produce, transport and market crude oil, bitumen, natural gas, NGLs and LNG on a worldwide basis. At December 31, 2023, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.

Total production of 1,826 MBOED increased 88 MBOED or 5 percent in 2023 compared with 2022, primarily due to new wells online in the Lower 48, Australia, Canada, China, Norway and Malaysia.

The increase in production during 2023 was partly offset by normal field decline.

After adjusting for closed acquisitions and dispositions, production increased by 73 MBOED or 4 percent.

Segment Results

Unless otherwise indicated, discussion of Segment Results is after-tax.

Alaska

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2023, Alaska contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Alaska reported earnings of $1,778 million in 2023, compared with earnings of $2,352 million in 2022. Earnings were negatively impacted by:

•Lower realized crude oil prices.

•Higher production and operating expenses due to higher well work and transportation related costs.

•Higher DD&A expenses due to higher rates primarily as a result of downward reserve revisions.

Earnings were positively impacted by lower taxes other than income taxes associated with lower realized crude oil prices.

Production

Average production decreased 5 MBOED in 2023 compared with 2022, primarily due to normal field decline.

The production decrease was partly offset by new wells online at our Western North Slope and Greater Kuparuk Area assets.

Exploration Activity

In the first quarter of 2023, we drilled the Bear-1 exploration well which was determined to be a dry hole, increasing exploration expenses by approximately $31 million before-tax. The well, located south of the Kuparuk River Unit and east of the Colville River on state lands, is in an area that we are continuing to evaluate. See Note 6.

Willow Update

In March 2023, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.

Lower 48

*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.

The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 2023, the Lower 48 contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.

Net Income (Loss)

Lower 48 reported earnings of $6,461 million in 2023, compared with earnings of $11,015 million in 2022. Earnings were negatively impacted by:

•Lower realized commodity prices.

•Higher DD&A expenses primarily due to higher rates from reserve revisions resulting from higher operating costs as well as higher production volumes.

•Higher production and operating expenses primarily due to higher production volumes and increased well work activity.

Earnings were positively impacted by:

•Higher sales volumes.

•Improved commercial performance and timing.

•Lower taxes other than income taxes driven by lower realized prices, partially offset by higher production volumes.

Production

Total average production increased 78 MBOED in 2023 compared with 2022, primarily due to new wells online from our development programs in Delaware Basin, Midland Basin, Eagle Ford and Bakken.

These production increases were partly offset by normal field decline.

Canada

*Average sales prices include unutilized transportation costs.

Our Canadian operations consist of the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. In 2023, Canada contributed seven percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income (Loss)

Canada operations reported earnings of $402 million in 2023 compared with earnings of $714 million in 2022. Earnings were negatively impacted by:

•Lower realized commodity prices.

•Absence of contingent payments received associated with the prior sale of certain assets to CVE. The term of CVE contingent payments ended in the second quarter of 2022.

Earnings were positively impacted by:

•Higher sales volumes primarily related to our Surmont acquisition which closed in October 2023. See Note 3.

•Absence of prior year exploration expenses related to the impairment of certain aged, suspended wells. See Note 6.

•A $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit. See Note 17.

Production

Total average production increased 19 MBOED in 2023 compared with 2022. The production increase was primarily due to:

•Higher volumes due to our Surmont acquisition in the fourth quarter of 2023. See Note 3.

•New wells online from our development program in the Montney.

These production increases were partly offset by normal field decline.

Surmont Acquisition

On October 4, 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont. Total consideration was approximately $2.7 billion in cash after customary adjustments, as well as future contingent payments of up to approximately $0.4 billion CAD (approximately $0.3 billion). Production from the acquired interest averaged approximately 62 MBD of bitumen in the fourth quarter of 2023. See Note 3.

Europe, Middle East and North Africa

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, and commercial and terminalling operations in the U.K. In 2023, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 16 percent of our consolidated natural gas production.

Net Income (Loss)

The Europe, Middle East and North Africa segment reported earnings of $1,189 million in 2023 compared with earnings of $2,244 million in 2022. Earnings were negatively impacted by:

•Lower realized commodity prices.

•Lower equity in earnings of affiliates primarily due to lower LNG sale prices.

•Lower commercial performance and timing.

•Lower sales volumes in Norway.

•Lower foreign exchange gains resulting from the USD strengthening against the NOK.

Consolidated Production

Average consolidated production increased 3 MBOED in 2023, compared with 2022. The consolidated production increase was primarily due to:

•Higher production in 2023 from additional interest acquired in Libya's Waha Concession in the fourth quarter of 2022.

The production increase was partly offset by:

•Normal field decline in Norway.

•Higher downtime on partner-operated assets in Norway.

Qatar Interest

During 2022, we were awarded a 25 percent interest in NFS3, a new joint venture with QatarEnergy to participate in the NFS LNG project. Formation of NFS3 closed in June 2023. See Note 3 and Note 4.

Exploration Activity

During 2023, we recorded $37 million before-tax as dry hole expense for the Norwegian Warka suspended discovery well on license PL1009 that was drilled in 2020.

Asia Pacific

The Asia Pacific segment consists of operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan. During 2023, Asia Pacific contributed five percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income (Loss)

Asia Pacific reported earnings of $1,961 million in 2023, compared with $2,736 million in 2022. Earnings were negatively impacted by:

•Absence of an after-tax gain of $534 million associated with the divestiture of our Indonesia assets. See Note 3.

•Lower realized commodity prices.

•Lower equity in earnings of affiliates resulting from lower LNG sales prices.

•Lower sales volumes.

Earnings were positively impacted by:

•Recognized tax benefits from the reversal of a tax reserve and deepwater tax incentives. See Note 17.

•Lower taxes other than income taxes primarily due to lower realized commodity prices.

Consolidated Production

Average consolidated production decreased 12 MBOED in 2023, compared with 2022. The decrease was primarily due to:

•Normal field decline.

•The divestiture of our Indonesia assets in the first quarter of 2022.

These production decreases were partly offset by development activity at Bohai Bay in China and new wells online in Malaysia.

Planned Acquisition Update

In March 2023, we announced that, subject to the closing of EIG's transaction with Origin Energy, we planned to take over operatorship of the upstream assets and purchase up to an additional 2.49 percent shareholding interest in APLNG. In December 2023, Origin Energy shareholders did not approve the transaction.

Other International

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

Earnings from our Other International operations improved $38 million in 2023, compared with 2022, primarily due to the absence of higher taxes related to legal settlements in 2022.

Corporate and Other

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense decreased $240 million in 2023, compared with 2022, primarily due to higher interest income in addition to lower interest expenses due to higher capitalized interest for longer term major projects. See Note 9.

Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $113 million in 2023 compared with 2022, primarily due to mark-to-market adjustments associated with certain compensation programs. See Note 16.

Technology includes our investments in low-carbon technologies as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG.

Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense. Earnings in “Other” decreased by $552 million in 2023 compared with 2022. This was primarily due to:

•Absence of a $474 million federal tax benefit. See Note 17.

•Absence of a $251 million gain associated with our CVE common shares, which were fully divested in the first quarter of 2022. See Note 5.

•Loss of $89 million associated with forward foreign exchange contracts to buy CAD, in support of our acquisition of additional working interest in Surmont. See Note 3.

•Absence of a gain of $62 million associated with 2022 debt restructuring transactions. See Note 9.

The decreases were offset by:

•Absence of a $101 million tax impact associated with the disposition of our Indonesia assets in the first quarter of 2022. See Note 3.

•Absence of an $81 million impact from certain legal accruals.

Port Arthur LNG Acquisition

In March, we acquired a 30 percent direct equity holding in PALNG, a joint venture for the development of Phase 1 of the Port Arthur LNG project. In addition, we entered into a 20-year agreement to purchase 5 MTPA of LNG offtake at the start of Phase 1 and a natural gas supply management agreement, whereby we will manage the feedgas supply requirements for Phase 1. Currently we anticipate start up in 2027. See Note 3.

Capital Resources and Liquidity

Financial Indicators

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, proceeds from asset sales, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 2023, the primary uses of our available cash were $11.2 billion to support our ongoing capital expenditures and investments program, $2.7 billion for the acquisition of an additional 50 percent working interest in Surmont, $5.4 billion to repurchase common stock, and $5.6 billion to pay the ordinary dividend and VROC. In addition to cash from operating activities, the other primary sources of additional capital were $2.7 billion in proceeds from long-term debt issuances to fund the Surmont acquisition and $1.4 billion net sales of short-term investments. In 2023, cash and cash equivalents decreased by $0.8 billion to $5.6 billion. See Note 9.

At December 31, 2023, we had cash and cash equivalents of $5.6 billion, short-term investments of $1.0 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.1 billion of liquidity. We believe current cash balances and cash generated by operations, 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, dividend payments and required debt payments.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities in 2023 totaled $20.0 billion, compared with $28.3 billion for 2022, and $17.0 billion for 2021. The decrease in cash provided by operating activities from 2022 is primarily due to lower realized commodity prices across all products, partly offset by higher sales volumes, net of associated production and operating costs.

The increase in cash provided by operating activities from 2022 compared to 2021 is primarily due to higher realized commodity prices, higher sales volumes mostly due to our acquisition of Shell Permian assets and the absence of the 2021 settlement of oil and gas hedging positions acquired from Concho. The increase in cash provided by operating activities was partly offset by foreign tax and royalty payments in Libya and foreign tax payments in Norway in addition to U.S. tax payments.

Our short- 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 absolute production volumes, as well as product and location mix, is another significant factor impacting our cash flows. Full-year production averaged 1,826 MBOED in 2023, an increase of 88 MBOED or 5 percent compared to 2022. First quarter 2024 production is expected to be 1.88 MMBOED to 1.92 MMBOED. 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; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively monitor and manage these factors, changes in production levels can cause variability in cash flows, although we generally experience less variability in our cash flows due to changes in production levels than due to changes in commodity prices.

To maintain or grow our production volumes on an ongoing basis, we must continue to add to our proved reserve base. Our estimates of our proved reserves generally increase as of a specified date as prices rise and decrease as prices decline. Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. For information on proved reserves, including both developed and undeveloped reserves, see the reserve table disclosures contained in “Supplementary Data – Oil and Gas Operations.” See “Item 1A—Risk Factors – Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business.”

As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, reserves may be revised upward or downward each year due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. It is not possible to reliably predict how revisions will impact future reserve quantities.

Investing Activities

In 2023, we invested $11.2 billion in capital expenditures and investments; $1.5 billion of which was primarily payments towards our investments in LNG projects, including PALNG, NFE4 and NFS3. See Note 3. The remaining $9.7 billion funded our operating capital program. Capital expenditures invested in 2022 and 2021 were $10.2 billion and $5.3 billion, respectively. See the “Capital Expenditures and Investments” section.

In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $2.7 billion of cash after customary adjustments. We funded this transaction by issuing new long-term debt. See Note 3 and Note 9.

Proceeds from asset sales were $0.6 billion in 2023 compared with $3.5 billion in 2022. In 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of CVE, proceeds of approximately $1.5 billion, primarily from asset divestitures in our Asia Pacific and Lower 48 segments, and $0.5 billion in contingent payments associated with prior divestitures. See Note 3 and Note 5.

In December 2021, we completed our acquisition of Shell’s assets in the Delaware Basin for cash consideration of approximately $8.7 billion after customary adjustments. We funded this transaction with cash on hand. We completed our acquisition of Concho on January 15, 2021 in an all-stock transaction. The assets acquired in the transaction included $382 million of cash. The net impact of these items is recognized within “Acquisition of businesses, net of cash acquired” on our consolidated statement of cash flows. See Note 3.

In 2021, total proceeds from asset dispositions were $1.7 billion. We received cash proceeds of $250 million from the sale of noncore assets in our Lower 48 segment, $1.1 billion from sales of our investment in CVE common shares and $244 million of contingent payments related to dispositions completed before 2021. See Note 3 and Note 5.

We invest in short-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits, commercial paper, as well as debt securities classified as available for sale. Funds for short-term needs to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities within the 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. See Note 12 and Note 19.

Investing activities in 2023 included net sales of $1,373 million of investments. We had net sales of $2,111 million of short-term instruments and net purchases of $738 million of long-term instruments. See Note 19.

Financing Activities

Our debt balance at December 31, 2023 was $18.9 billion compared with $16.6 billion at December 31, 2022. The current portion of debt, including payments for finance leases, is $1.1 billion. In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities. See Note 9.

In 2022, we repurchased notes, retired floating rate debt, and executed a debt refinancing comprised of concurrent transactions including new debt issuances, a cash tender offer and debt exchange offers. In aggregate, these transactions along with naturally maturing debt, reduced the company's total debt by $3.3 billion.

In 2022, we refinanced our revolving credit facility from a total aggregate principal amount of $6.0 billion to $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 agreement calls for commitment fees on available, but unused, amounts. The 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 ConocoPhillips Company’s ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. 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 December 31, 2023.

In December 2023, Fitch affirmed our long-term credit ratings. The current credit ratings on our long-term debt are:

•Fitch: “A” with a “stable” outlook

•S&P: “A-” with a “stable” outlook

•Moody's: "A2" with a "stable" outlook

See Note 9 for additional information on debt and the revolving credit facility.

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 rating 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.

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 December 31, 2023 and December 31, 2022, we had direct bank letters of credit of $340 million and $368 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 amount of various types of debt and equity securities.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section.

Our debt balance at December 31, 2023, was $18.9 billion, an increase of $2.3 billion from the balance at December 31, 2022 of $16.6 billion. In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases. In 2022, we executed concurrent debt refinancing transactions, repurchased existing notes, and retired floating rate notes upon natural maturity, that in aggregate reduced our total debt by $3.3 billion while also lowering our annual cash interest expense and extending the weighted average maturity of our debt portfolio. See Note 9 for information regarding debt and Note 19 for information regarding non-cash consideration of the Surmont transaction.

In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. We plan to deliver a compelling, growing ordinary dividend, through-cycle share repurchases and a VROC payment. The VROC provides a flexible tool for meeting our commitment of returning greater than 30 percent of cash from operating activities during periods where commodity prices are meaningfully higher than our planning price range. Our 2023 total capital returned was $11 billion.

Consistent with our commitment to deliver value to shareholders, for the full year of 2023, we paid ordinary dividends of $2.11 per common share and VROC payments of $2.50 per common share. This was an increase over 2022 when we paid ordinary dividends of $1.89 and VROC payments of $2.60 per common share and an increase over 2021 when we paid an ordinary dividend of $1.75 per common share. In February 2024, we declared a first quarter ordinary dividend of $0.58 per common share and a VROC payment of $0.20 per common share, both payable March 1, 2024, to shareholders of record on February 19, 2024.

The ordinary dividend and VROC are subject to numerous considerations and are determined and approved each quarter by the Board of Directors. All VROC payments to date have been declared along with the ordinary dividend, but paid in the following quarter. However, beginning in the first quarter of 2024, we plan to pay any quarterly dividend and VROC payment concurrently and will announce such payments in the same quarter they will be paid.

In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of our common stock to support our plan for future share repurchases. Share repurchases were $5.4 billion, $9.3 billion, and $3.6 billion in 2023, 2022, and 2021, respectively. As of December 31, 2023, share repurchases since the inception of our current program totaled 383.4 million shares and $28.8 billion. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors.

For more information on factors considered when determining the levels of returns of capital see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

As of December 31, 2023, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $29.7 billion. We expect to fulfill $7.4 billion of these obligations in 2024. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations of $9.8 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase obligations of $17.8 billion are related to market-based contracts for commodity product purchases with third parties. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

Capital Expenditures and Investments

* Excludes capital related to acquisitions of businesses, net of cash acquired.

Our capital expenditures and investments for the three-year period ended December 31, 2023, totaled $26.7 billion. The 2023 capital expenditures and investments supported key operating activities and acquisitions, primarily:

•Appraisal and development activities in Alaska related to the Western North Slope and development activities in the Greater Kuparuk Area.

•Development and exploration activities in the Lower 48, primarily in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.

•Appraisal and development activities at Montney as well as development and optimization of Surmont in Canada.

•Development activities across assets in Norway.

•Continued development activities in Malaysia and China.

•Capital primarily associated with our investments in PALNG, NFE4 and NFS3.

2024 Capital Budget

In February 2024, we announced our 2024 operating plan capital is expected to be between $11.0 to $11.5 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.

Guarantor Summarized Financial Information

We have various cross guarantees among 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 this presentation.

Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented separately below:

Summarized Income Statement Data

*Includes approximately $7.9 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

Contingencies

We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See “Critical Accounting Estimates” and Note 11 for information on contingencies.

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. See Note 17.

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:

•U.S. Federal Clean Air Act, which governs air emissions;

•U.S. Federal Clean Water Act, which governs discharges to water bodies;

•European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH);

•U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;

•U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;

•U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;

•U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;

•U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages; and

•European Union Trading Directive resulting in European Emissions Trading Scheme.

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also establish standards and impose obligations for the remediation of releases of hazardous substances and hazardous wastes. In most cases, these regulations require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the U.S. and Canada.

An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, potential new laws, regulations and permitting requirements from various state environmental agencies, and others could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

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 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 December 31, 2023, 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 most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $791 million in 2023 and are expected to be approximately $937 million and $946 million in 2024 and 2025, respectively. Capitalized environmental costs were $393 million in 2023 and are expected to be about $438 million and $450 million in 2024 and 2025, respectively.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA, and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct or once conducted operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation but which are not currently the subject of CERCLA, RCRA, or other agency enforcement activities. The laws that require or address environmental remediation may apply retroactively and regardless of fault, the legality of the original activities or the current ownership or control of sites. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2023, our balance sheet included total accrued environmental costs of $184 million, compared with $182 million at December 31, 2022, for remediation activities in the U.S. and Canada. 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 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 and Note 11 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 focusing on GHG 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. Examples of legislation and precursors for possible regulation that do or could affect our operations include:

•European Emissions Trading Scheme (ETS), the program through which many of the EU member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2023 was approximately $28 million (net share before-tax).

•U.K. Emissions Trading Scheme, the program with which the U.K. has replaced the ETS. Our cost of compliance with the U.K. ETS in 2023 was approximately $0.8 million (net share before-tax).

•The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. The total cost of compliance related to this regulation in 2023 was approximately $3.5 million (net share before-tax).

•The U.S. government has announced on September 17, 2021 the Global Methane Pledge, a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.

•Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon legislation in 2023 was approximately $35 million (net share before-tax). We also incur a carbon tax for emissions from fossil fuel combustion in our British Columbia and Alberta operations in Canada, totaling approximately $8.2 million (net share before-tax).

•The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change, setting out a process for achieving global emissions reductions. The new administration has recommitted the United States to the Paris Agreement, and a significant number of U.S. state and local governments and major corporations headquartered in the U.S. have also announced related commitments. Accordingly, the U.S. administration set a new target on April 22, 2021 of a 50 to 52 percent reduction in GHG emissions from 2005 levels in 2030.

•The U.S. EPA announced the final New Source Performance Standards (OOOOb) and Emissions Guidelines (OOOOc) rulemaking on December 2, 2023. While industry is awaiting final publication of the rulemaking, we do anticipate that implementing this regulation across our U.S. portfolio will result in additional compliance costs. The proposed sub-part W regulations and the Methane Emission Reduction Program (MERP), passed as part of the Inflation Reduction Act of 2022 will potentially result in impacts to our business. The implementation of the MERP fee, while applicable for 2024 emissions, has not yet been finalized by the EPA.

•Governments and financial regulators are developing new reporting rules requiring increased disclosure around a range of sustainability topics. In March 2022 the U.S. SEC proposed rule changes that would require registrants to include certain climate-related disclosures in their registration statements and periodic reports; In January 2023 the EU finalized the Corporate Sustainability Reporting Directive that will require more detailed sustainability reporting; in June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards; and in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state. The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement.

•The U.S. Council on Environmental Quality is preparing to finalize revised regulations under the National Environmental Policy Act (NEPA Phase 2), along with corresponding Guidance on the Consideration of GHG Emissions and Climate Change, in early 2024. The new regulatory framework’s emphasis on avoiding and minimizing climate impacts increases uncertainty associated with the federal environmental review and permitting process for oil and gas activities.

Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:

•Whether and to what extent legislation or regulation is enacted;

•The timing of the introduction of such legislation or regulation;

•The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation;

•The price placed on GHG emissions (either by the market or through a tax);

•The GHG reductions required;

•The price and availability of offsets;

•The amount and allocation of allowances;

•Technological and scientific developments leading to new products or services;

•Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature); and

•Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

See 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 Note 11 for information on climate change litigation.

Company Response to Climate-Related Risks

In 2020, we adopted a Paris-aligned 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 achieve 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.

•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 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 for alignment on GHG emissions reductions.

•Contributing to an orderly transition

◦Building an attractive LNG portfolio.

◦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 and with the shape and pace of technology and policy yet to be determined, setting and meeting Scope 3 targets would require a shift of production to other global operators that have established less ambitious targets or no targets to reduce their own operational emissions or do not have any other ambitions or plans to manage climate-related risks, potentially eroding energy security and affordability as well as undercutting global climate change objectives. 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 regulatory action, such as support for the direct regulation of methane.

In support of addressing our Scope 1 and 2 emissions, in 2023, we made progress in several key areas.

•Continued to refine our Paris-aligned climate risk strategy.

•Accelerated our GHG 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 in the OGMP 2.0 Initiative.

•Implemented our new near-zero 2030 methane emissions intensity target of approximately 1.5 kilogram carbon dioxide equivalent per BOE or of 0.15 percent of gas produced.

Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technologies organization. See Item 1A. Risk Factors—Our ability to successfully execute on our energy transition plans is subject to a number of risks and uncertainties and may be costly to achieve.

New Accounting Standards

For discussion of new accounting standards, see Note 25.

Critical Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1 for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been recognized.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves, including estimates of future expirations, and pools that leasehold information with others in similar geographic areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.

At year-end 2023, we held $4.4 billion of net capitalized unproved property costs which consisted primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $3.0 billion is concentrated in the Delaware and Midland Basins, where we have an ongoing significant and active development program. Outside of the Delaware and Midland Basins, the remaining $1.4 billion is primarily concentrated in Canada. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify development.

If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or coventurer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves.

At year-end 2023, total suspended well costs were $184 million, compared with $527 million at year-end 2022. For additional information on suspended wells, including an aging analysis, see Note 6.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our geosciences and reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates. See “Supplementary Data - Oil and Gas Operations” for additional information.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to PSCs, reported under the “economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. We would expect reserves from these contracts to decrease when product prices rise and increase when prices decline.

The estimation of proved reserves is also important to the income statement because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2023, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $62 billion and the DD&A recorded on these assets in 2023 was approximately $8.1 billion. The estimated proved developed reserves for our consolidated operations were 3.8 billion BOE at the end of 2022 and 3.7 billion BOE at the end of 2023. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2023 would have increased by an estimated $894 million.

Business Combination—Valuation of Oil and Gas Properties

For business combinations, management applies the principles of acquisition accounting under FASB ASC Topic 805 – “Business Combinations” and allocates the purchase price to assets acquired and liabilities assumed, based on their estimated fair values as of the acquisition date. Estimating the fair values involves making various assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved oil and gas properties. For significant business combinations, management generally utilizes a discounted cash flow approach, based on market participant assumptions, and considers engaging third party valuation experts in preparing fair value estimates.

Significant inputs incorporated within the valuation include future commodity price assumptions and production profiles of reserve estimates, the pace of drilling plans, future operating and development costs, inflation rates, and discount rates using a market-based weighted average cost of capital determined at the time of the acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ. See Note 3.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed using management’s assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment in the periods in which the determination is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period. See Note 6 and Note 7.

Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. Since quoted market prices are usually not available, the fair value is typically based on the present value of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period. See the “APLNG” section of Note 4.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change between the time of initial recognition of the liability and future settlement of our obligation.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they 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. See Note 8.

Projected Benefit Obligations

The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by $600 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount rate assumption would increase annual benefit expense by $50 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual benefit expense by $40 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a significant reduction in the expected years of future service of present employees or the elimination of the accrual of defined benefits for some or all of their future services for a significant number of employees, we could recognize a curtailment gain or loss. See Note 16.

Contingencies

A number of claims and lawsuits are made against the company arising in the ordinary course of business. Management exercises judgment related to accounting and disclosure of these claims which includes losses, damages, and underpayments associated with environmental remediation, tax, contracts, and other legal disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to amounts recognized and disclosed considering changes to the probability of additional losses and potential exposure. However, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration, or other third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability shared with other responsible parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and Note 11.

Income Taxes