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Item 7. Management’s Discussion and Analysis

2024-02-15 compared with 2023-02-16 · 349 added, 350 removed, 713 unchanged (50% of the section changed)

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Results of Operations

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance.

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 “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 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.

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“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) attributable to ConocoPhillips.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss).

Business Environment and Executive Overview

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conventional assets in North America, Europe, Africa and Asia;

LNG developments;

oil sands assets in Canada;

and an inventory of global conventional and unconventional exploration prospects.

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.

In 2022, the energy landscape continued to improve with commodity prices ultimately reaching a 10-year high before decreasing in the second half of the year due to macroeconomic concerns.

We expect prices will continue to be cyclical and volatile.

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 highly disciplined in our investment decisions and continually monitor market fundamentals, including the impacts associated with the conflict in Ukraine, OPEC Plus supply updates, global demand for our products, oil and gas inventory levels, governmental policies, inflation, supply chain disruptions and the fluctuating global COVID-19 impacts.

The macro-environment, including the energy transition, continues to evolve.

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:

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We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders.

Our value proposition to deliver competitive returns to stockholders through price cycles is guided by foundational principles that support our Triple Mandate.

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.

Our actions throughout 2022 reinforced our differential value proposition.

Demonstrating our commitment to maintaining and enhancing balance sheet strength, in 2022, we executed several activities focused on debt reduction, including early retiring and refinancing some of our debt.

In aggregate, these transactions along with naturally maturing debt reduced the company's total debt by $3.3 billion.

These activities facilitate our ability to achieve our previously announced $5 billion debt reduction target by the end of 2026, while also reducing the company's annual cash interest expense.

ConocoPhillips 2022 10-K

Management’s Discussion and Analysis

Total company production in 2023 was 1,826 MBOED, yielding cash provided by operating activities of $20 billion.

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We also returned $3.0 billion to shareholders from the VROC in 2023.

In the first quarter of 2022, we completed the paced monetization program of our Cenovus Energy (CVE) common shares and used the proceeds for a portion of our share repurchase program.

In total for 2023, we returned $5.4 billion to shareholders through share repurchases.

In October 2022, our Board of Directors approved an increase to our share repurchase authorization, increasing it from $25 billion to $45 billion to support our plan for future share repurchases.

As of December 31, 2023, we have repurchased $28.8 billion of the $45 billion authorized share repurchase program.

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We also declared a first quarter ordinary dividend of 58 cents per share and a VROC of 20 cents per share.

In 2022, we took several steps to expand our global LNG business.

In the first quarter, we increased our equity share in Australia Pacific LNG (APLNG) by 10 percent to 47.5 percent.

We were also awarded a 25 percent interest in each of two new joint ventures with QatarEnergy that will participate in the North Field East (NFE) and North Field South (NFS) LNG projects.

Formation of the NFE joint venture (QG8) closed in December 2022 and we anticipate that the formation of the NFS joint venture (QG12) will close in early 2023.

Also, in 2022, we executed a 15-year regasification agreement at the recently announced German LNG Terminal at Brunsbuttel.

Domestically, in November 2022, we entered into several agreements with Sempra entities in connection with the Port Arthur LNG (PALNG) facility, including a Sales and Purchase Agreement for 5 MTPA of LNG offtake at the start-up of Phase 1 of the PALNG facility, and an Equity Sale and Purchase Agreement, whereby we will acquire 30 percent of the equity in Phase 1 of Port Arthur LNG.

Development of the PALNG facility is subject to completing required commercial agreements and resolving a number of risks and uncertainties, obtaining financing and reaching a final investment decision, among other factors.

As part of our ongoing portfolio high-grading and optimization efforts, in the first quarter of 2022, we completed two transactions in our Asia Pacific segment, including the above-mentioned acquisition of additional interest in APLNG as well as the sale of our interests in Indonesia.

In addition to those transactions, throughout 2022, we completed the sale of certain noncore assets in our Lower 48 segment.

For more information on APLNG, see Note 4 and for more information on dispositions, see Note 3 .

In 2022, we reaffirmed and improved upon our commitment to demonstrate responsible and reliable ESG performance by publishing our Plan for the Net-Zero Energy Transition (the 'Plan'), which is built upon our Triple Mandate.

In addition, we continue to expand upon our Paris-aligned climate risk framework that we adopted in 2020.

In July 2022, we joined the Oil and Gas Methane Partnership (OGMP) 2.0 initiative.

In October 2022, we demonstrated further evidence of our commitment by setting a new 2030 methane emissions intensity target of approximately 0.15 percent of gas produced, consistent with our commitment to OGMP 2.0.

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.

Production increased 171 MBOED or 11 percent in 2022, compared to 2021.

Production for 2022 was 1,738 MBOED.

After adjusting for closed acquisitions and dispositions, the conversion of previously acquired Concho-contracted volumes from a two-stream to a three-stream basis and 2021 Winter Storm Uri impacts, production decreased by 16 MBOED or 1 percent.

Organic growth from Lower 48 and other development programs more than offset decline;

however, production was lower overall, primarily due to fourth quarter weather impacts and downtime in Lower 48.

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.

ConocoPhillips 2023 10-K

Management’s Discussion and Analysis

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.

S ee 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.

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.

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.

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

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

ended the year with cash and cash equivalents and restricted cash of $6.7 billion and short-term investments of $2.8 billion;

• Distributed $15 billion to shareholders through three-tier framework including $5.7 billion in cash through the ordinary dividend and VROC and $9.3 billion through share repurchases, representing 53 percent of cash provided by operating activities;

• Expanded global LNG business through participation in QatarEnergy's NFE and NFS projects;

executed 15-year regasification agreement at German LNG Terminal;

acquired additional 10 percent interest in APLNG;

signed 20-year agreement for 5 MTPA of LNG offtake and executed agreement to purchase 30 percent equity stake in Phase 1 of Port Arthur LNG;

• Delivered full-year production of 1,738 MBOED and record Lower 48 production;

• Fully integrated acquired Permian assets and executed multiple acreage swaps, coring up approximately 25,000 acres since acquisition to provide over a year's worth of additional two mile-plus long-lateral drilling inventory;

• Received license extension for Norway's Greater Ekofisk area to 2048 and license adjustments for China's Bohai Penglai Fields to 2039;

• Generated $3.5 billion in disposition proceeds through monetization of the company's CVE shares and noncore asset sales;

• Retired $3.3 billion in debt toward the company's $5 billion debt reduction target;

• Joined OGMP 2.0;

published a Plan for the Net-Zero Energy Transition and set a new 2030 methane emissions intensity target, enhancing our commitment to ESG;

• Recorded 2022 year-end proved reserves of 6.6 billion BOE, with a total reserve replacement ratio of 176 percent including closed acquisitions and dispositions.

• 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;

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

ConocoPhillips 2023 10-K

Management’s Discussion and Analysis

Business Environment

WTI crude oil prices averaged $94 per barrel in 2022, compared with $68 per barrel in 2021.

The energy industry has periodically experienced this type of volatility due to fluctuating supply-and-demand conditions and such volatility may persist in the future.

Commodity prices are the most significant factor impacting our profitability, reinvestment of operating cash flows into our business and distributions to shareholders.

We are guided by our Triple Mandate and our foundational principles to deliver on our differential value proposition to create value through price cycles.

Our foundational principles include maintaining balance sheet strength, peer leading distributions, disciplined investments and demonstrating responsible and reliable ESG performance, all of which support strong financial returns.

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, and in 2021 committed to reducing gross debt by $5 billion by the end of 2026.

In 2022 we executed several activities focused on debt reduction and, combined with naturally maturing debt, reduced the company's total debt by $3.3 billion.

This will reduce interest expense and provide resilience in periods of volatility.

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.

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This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders.

In 2022, we returned $5.7 billion to shareholders through our ordinary dividend and VROC and $9.3 billion through share repurchases partially sourced from monetization of our CVE common shares.

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 October 2022, our Board of Directors approved an increase to our share repurchase authorization from $25 billion to $45 billion to support our plan for future share repurchases.

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 “It em 1A—Risk Factors Our ability to execute our capital return program is subject to certain considerations.”

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 sustain production throughout the price cycles.

Free cash flow provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.

ConocoPhillips 2022 10-K

Management’s Discussion and Analysis

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 dollars to develop newly discovered fields, maintain existing fields, and construct pipelines and LNG facilities.

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 includes capital infrastructure, foreign exchange, cost of carbon, price-related inflation and G&A.

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.

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◦ Control our costs.

Controlling operating and overhead costs, without compromising safety or environmental stewardship, is a high priority.

Using various methodologies, we monitor these costs monthly, on an absolute-dollar basis and a per-unit basis and report to management.

Managing operating and overhead costs is critical to maintaining a competitive position in our industry, particularly in a low commodity price environment.

The ability to control our operating and overhead costs positively impacts our ability to deliver strong cash from operations.

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.

In 2022, we expanded upon our global LNG business by increasing our ownership in APLNG by 10 percent to 47.5 percent.

In addition, we were also awarded interests in the NFE and NFS LNG projects in Qatar, signed agreements to purchase an interest in Port Arthur LNG in the U.S., and signed a 15-year regasification agreement with the German LNG Terminal at Brunsbuttel.

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.

As such, in 2022 we completed the sale of Indonesia and certain noncore assets in the Lower 48 segment.

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.

ConocoPhillips 2023 10-K

Management’s Discussion and Analysis

◦ Add to our proved reserve base.

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

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.

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.

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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 176 percent in 2022, reflecting a net increase from development drilling activity as well as higher prices.

Our organic reserve replacement, which excludes a net decrease of 6 MMBOE from sales and purchases, was 177 percent in 2022.

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.

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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.

ConocoPhillips 2022 10-K

Management’s Discussion and Analysis

• Environmental Social and Governance.

ConocoPhillips seeks to fulfill our mission of delivering energy to the world through an integrated management system approach that assesses sustainability-related business risks and opportunities as part of our decision-making process.

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

• 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.

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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 early 2022, we reaffirmed and improved our commitment to demonstrate responsible and reliable ESG performance and address climate-related risks by publishing our Plan for the Net Zero Energy Transition, which outlines our approach and progress to address risks specific to the energy transition.

ConocoPhillips believes 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.

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.

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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.

ConocoPhillips 2023 10-K

Management’s Discussion and Analysis

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 disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC Plus and other producing countries, environmental laws, tax regulations, governmental policies, global health crises and weather-related disruptions.

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 over the past three years:

Brent crude oil prices averaged $101.19 per barrel in 2022, an increase of 43 percent compared with $70.73 per barrel in 2021.

Similarly, average WTI crude oil prices increased 39 percent from $67.92 per barrel in 2021 to $94.23 per barrel in 2022.

Prices were higher through 2022 due to ongoing global economic recovery following 2020's COVID impacts, supply disruptions caused by Russia's invasion of Ukraine and resulting sanctions, OPEC supply restraint and supply chain bottlenecks limiting U.S.

production growth.

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.

ConocoPhillips 2023 10-K

Management’s Discussion and Analysis

Henry Hub natural gas prices increased 73 percent from an average of $3.85 per MMBTU in 2021 to $6.65 per MMBTU in 2022.

Natural gas prices increased due to modest growth in domestic production, healthy domestic demand and strong levels of feedgas demand for LNG exports to Europe and Asia.

Our realized bitumen price increased 48 percent from an average of $37.52 per barrel in 2021 to $55.56 per barrel in 2022.

The increase was largely driven by strength in WTI, reflective of increasing global demand and sanctions on Russian exports.

The weakness of WCS to WTI differential at Hardisty was primarily caused by U.S.

strategic petroleum reserve release, discounted Russian crude oil and weak heavy fuel pricing.

We continue to optimize bitumen price realizations through optimizing diluent recover unit operation, blending and transportation strategies.

Our worldwide annual average realized price increased 46 percent from $54.63 per BOE in 2021 to $79.82 per BOE in 2022 primarily due to higher commodity prices.

Production and Capital

2023 operating plan capital expenditure guidance is $10.7 to $11.3 billion, which includes $1.6 to $2.0 billion for anticipated major project spending at NFE, NFS, PALNG and Willow and $9.1 to $9.3 billion for ongoing development drilling programs;

exploration and appraisal activities;

base maintenance;

and projects to reduce the company's Scope 1 and 2 emissions intensity and fund investments in several early-stage low-carbon opportunities that address end-use emissions.

Production guidance is 1.76 to 1.80 MMBOED in 2023.

First quarter 2023 production is expected to be 1.72 MMBOED to 1.76 MMBOED, which includes 35 MBOED of turnaround and stabilizer expansion in Eagle Ford.

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

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and Other International.

Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest expense, premiums incurred on the early retirement of debt, corporate overhead, certain technology activities, as well as licensing revenues.

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.

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Consolidated Results

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

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

Millions of Dollars

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Corporate and Other (821) (330) (210)

Net income (loss) attributable to ConocoPhillips $ 18,680 8,079 (2,701)

Net Income (loss) attributable to ConocoPhillips increased $10,601 million in 2022.

Earnings were positively impacted by:

• Higher realized commodity prices.

• Higher sales volumes primarily due to our Shell Permian acquisition, partly offset by assets divested.

• Higher equity in earnings of affiliates, primarily due to higher LNG sales prices and volumes as well as the additional 10 percent interest in APLNG we acquired in the first quarter of 2022.

• Absence of a $682 million after-tax impairment of our APLNG investment included within our Asia Pacific segment.

• Recognition of a $515 million tax benefit related to the closing of an IRS audit.

See Note 17 .

• Gain on dispositions primarily due to a $462 million after-tax gain related to the divestiture of our Indonesia assets, higher contingent payments related to prior dispositions in our Canada and Lower 48 segments and the absence of a $137 million after-tax loss related to the divestiture of noncore assets in our Other International segment from 2021.

• Absence of restructuring and transaction expenses of $341 million after-tax related to our Concho and Shell Permian acquisitions.

• Absence of realized losses on hedges of $233 million after-tax related to derivative positions acquired in our Concho acquisition.

Net income (loss) $ 10,957 18,680 8,079

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.

• 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 other expenses primarily related to an after-tax gain of $62 million associated with the extinguishment of debt from the first quarter of 2022.

These increases in net income (loss) were partly offset by:

• Higher income tax provision.

• Higher taxes other than income taxes, production and operating expenses and DD&A expenses due to higher prices, production volumes, primarily from our Shell Permian acquisition, and inflation.

Partially offsetting the increase in DD&A expenses were lower rates from reserve revisions.

• A gain of $251 million after-tax on our Cenovus Energy (CVE) common shares in 2022, as compared to a $1,040 million after-tax gain on those shares in 2021.

• Absence of an after-tax gain of $194 million recognized for a final investment decision (FID) bonus associated with our Australia-West divestiture in 2020.

• 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.

• 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.

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 .

• Higher exploration expenses primarily related to the impairment of certain aged, suspended wells in our Canada segment and increased dry hole expenses in our Europe, Middle East and North Africa segment.

• 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.

ConocoPhillips 2023 10-K

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

Sales and other operating revenues increased $32,666 million in 2022, mainly due to higher realized commodity prices and higher sales volumes, primarily due to our Shell Permian acquisition, partially offset by assets divested.

Equity in earnings of affiliates increased $1,249 million in 2022, primarily due to higher earnings driven by higher LNG and crude prices as well as the additional 10 percent interest in APLNG which was acquired in the first quarter of 2022.

Gain on dispositions increased $591 million in 2022, primarily due to the recognition of a gain of $534 million from our Indonesia divestiture, the absence of a $179 million loss associated with the sale of noncore assets in our Other International segment and higher contingent payments in our Canada and Lower 48 segments than in 2021.

These increases were partially offset by the absence of a $200 million gain for a FID bonus associated with our Australia-West divestiture recognized in the first quarter of 2021.

Other income (loss) decreased $699 million in 2022, primarily due to the absence of mark-to-market gains associated with our CVE common shares which were fully divested in the first quarter of 2022.

The decrease was partially offset by higher interest income earned due to rising rates and investments.

Purchased commodities increased $15,813 million in 2022, primarily in line with higher gas and crude prices and volumes.

Production and operating expenses increased $1,312 million in 2022, due to higher volumes, primarily due to our Shell Permian acquisition, inflation and commodity price impacts.

Selling, general and administrative expenses decreased $96 million in 2022, primarily due to the absence of transaction and restructuring expenses associated with our Concho and Shell Permian acquisitions, partially offset by higher compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs.

Exploration expenses increased $220 million in 2022, primarily due to the impairment of certain aged, suspended wells in our Canada segment as well as increased dry hole expenses related to our 2022 exploration and appraisal campaign in Norway.

DD&A increased $296 million in 2022 mainly due to higher overall production volumes primarily due to our Shell Permian acquisition, partially offset by lower rates from reserve additions from development drilling and higher prices and the absence of DD&A from divested assets.

Impairments decreased $686 million in 2022, primarily due to the absence of an impairment of our APLNG investment included within our Asia Pacific segment in 2021.

For additional information, see Note 7 and Note 13 .

Taxes other than income taxes increased $1,730 million in 2022, caused primarily by higher commodity prices and higher sales volumes.

Other Expenses decreased $149 million primarily related to a gain of $127 million associated with the extinguishment of debt from the first quarter of 2022.

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.

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.

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.

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

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Results of Operations Table of Contents

We explore for, produce, transport and market crude oil, bitumen, LNG, natural gas and NGLs on a worldwide basis.

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 1,738 MBOED increased 171 MBOED or 11 percent in 2022 compared with 2021, primarily due to:

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

• Acquisitions including Shell Permian in the Lower 48 and additional working interest at APLNG in our Asia Pacific segment.

• Conversion of previously acquired Concho contracted volumes from a two-stream to a three-stream basis.

The increase in production during 2022 was partly offset by:

• Normal field decline.

• Divestiture of our Indonesia assets and noncore assets in the Lower 48 segment.

Production for 2022 was 1,738 MBOED.

Organic growth from Lower 48 and other development programs more than offset decline;

however, production was lower overall, primarily due to fourth quarter weather impacts and downtime in Lower 48.

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.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ 1,778 2,352 1,386

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In 2023, Alaska contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Net Income (Loss)

Alaska reported earnings of $1,778 million in 2023, compared with earnings of $2,352 million in 2022.

Earnings were positively impacted by higher realized commodity prices.

Earnings were negatively impacted by:

• Higher taxes other than income taxes associated with higher realized commodity prices and higher production volumes.

• Higher production and operating expenses driven primarily by response costs associated with a first quarter subsurface gas release at Alpine drill site CD1 and higher activity comprised of well workovers and gas injections.

Average production increased 3 MBOED in 2022 compared with 2021, primarily due to:

• New wells online at our Western North Slope assets.

• Increased development activity at Greater Prudhoe Area and Greater Kuparuk Area assets.

• Higher produced gas volumes in our Greater Prudhoe Area.

The production increase was partly offset by normal field decline.

• 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.

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.

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.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ 6,461 11,015 4,932

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Total Production (MBOED)

1,067 989 780

Average Sales Prices

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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) Attributable to ConocoPhillips

Net Income (Loss)

Lower 48 reported earnings of $6,461 million in 2023, compared with earnings of $11,015 million in 2022.

Earnings were positively impacted by:

• Higher realized prices.

• Higher sales volumes primarily related to our Shell Permian Acquisition.

• Absence of one-time impacts from our Concho and Shell Permian acquisitions including realized losses on hedges related to derivative positions acquired in our Concho acquisition and higher selling, general and administrative expenses for transaction and restructuring charges.

See Note 12 .

Earnings were negatively impacted by:

• Higher production and operating expenses, DD&A expenses and taxes other than income taxes primarily due to higher production volumes, primarily from our Shell Permian acquisition, realized commodity prices and inflation.

Partially offsetting the increase in DD&A expenses were lower rates from reserve additions, primarily from additional development drilling in our unconventional plays and certain technical revisions.

Total average production increased 209 MBOED in 2022 compared with 2021, primarily due to:

• New wells online from our development programs in Delaware Basin, Eagle Ford, Midland Basin and Bakken.

• Higher volumes due to our Shell Permian acquisition, partially offset by assets divested.

• Conversion of previously acquired Concho contracted volumes from a two-stream to a three-stream basis.

• 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.

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.

Asset Acquisitions and Dispositions

We completed multiple divestitures of noncore oil and gas assets during 2022 totaling approximately $680 million in proceeds after customary adjustments.

These divested assets averaged approximately 18 MBOED.

We also cored up strategic positions through acquisitions of approximately $250 million after customary adjustments.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ 402 714 458

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*Average sales prices include unutilized transportation costs.

Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich Montney unconventional play in British Columbia and commercial operations.

In 2022, Canada contributed six percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

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 positively impacted by:

• Higher realized prices.

• Contingent payments of $282 million in 2022 associated with the sale of certain assets to CVE in 2017 compared with $246 million in 2021.

Earnings were negatively impacted by:

• Higher exploration expenses primarily related to the impairment of certain aged, suspended wells.

• Lower sales volumes.

• Higher production and operating expenses primarily due to higher fuel gas and electricity prices at Surmont.

Total average production decreased 9 MBOED in 2022 compared with 2021.

The production decrease was primarily due to:

• Normal field decline.

• Higher royalty rates across the segment due to higher commodity prices.

• Planned turnarounds in our Montney assets and at the Surmont Central Processing Facility 1.

These production decreases were partly offset by new wells online in our Montney asset.

• 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.

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

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

See Note 17 .

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.

• 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.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ 1,189 2,244 1,167

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Natural gas ($ per mcf) 12.68 33.39 13.27

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea;

the Norwegian Sea;

and commercial and terminalling operations in the U.K.

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) Attributable to ConocoPhillips

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 positively impacted by:

• Higher realized prices.

• Higher equity in earnings of affiliates primarily due to higher LNG sale prices.

• Foreign exchange gains as the USD strengthened against the Norwegian Kroner.

Earnings were negatively impacted by:

• Lower sales volumes.

• 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 decreased 10 MBOED in 2022, compared with 2021.

The consolidated production decrease was primarily due to:

• Normal field decline.

• Field-wide turnarounds in the Greater Ekofisk Area of Norway.

• Unplanned downtime across our Norway assets.

These production decreases were partly offset by:

• New wells online, improved performance and higher gas exports in Norway.

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 a new joint venture with QatarEnergy that will participate in the NFE LNG project.

Formation of the NFE joint venture (QG8) closed in December 2022.

Once complete, the NFE project will have the capacity to produce 32 MTPA.

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 .

Libya Acquisition

In November 2022, we, along with TotalEnergies completed the joint acquisition of Hess Libya Waha Ltd, which increased our interest in the Waha Concession by 4.1 percent to 20.4 percent.

Exploration Activity

In 2022, we drilled four operated wells and participated in one partner operated well, all of which were determined to be dry holes, including the Slagugle appraisal well which effectively delineated the 2020 discovery.

Slagugle is a discovery that we are continuing to evaluate.

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.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ 1,961 2,736 453

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Crude oil (MBD) 60 61 65

Natural gas liquids (MBD) — — 1

Natural gas (MMCFD) 48 114 360

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Crude oil ($ per bbl) $ 84.79 105.52 70.36

Natural gas liquids ($ per bbl) — — 33.21

Natural gas ($ per mcf) 3.95 5.84 6.56

At December 31, 2022, the Asia Pacific segment had operations in China, Malaysia, and Australia, and commercial operations in China, Singapore and Japan.

During 2022, Asia Pacific contributed five percent of our consolidated liquids production and six percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

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.

The increase in earnings was mainly due to:

• Higher equity in earnings of affiliates reflecting higher LNG sales prices as well as our increased interest in APLNG.

• Absence of a $688 million after-tax impairment on our APLNG investment.

See Note 4 and Note 13 .

• Higher realized crude prices.

• After-tax gain of $534 million associated with the divestiture of our Indonesian assets.

• Lower DD&A expenses driven by the divestiture of our Indonesia assets.

• Lower production and operating expenses primarily associated with the divestiture of our Indonesia assets and lower production costs in China.

Earnings were negatively impacted by:

• Absence of an after-tax gain of $200 million recognized in the first quarter of 2021 related to a contingent payment from our Australia-West divestiture in 2020.

See Note 3 and Note 11 .

• Lower sales volumes primarily due to the divestiture of our Indonesia assets.

• Higher taxes other than income taxes primarily due to higher realized crude oil prices.

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

• 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

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The decrease was primarily due to:

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

• 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.

Asset Acquisitions and Dispositions

In the first quarter of 2022, we completed the acquisition of an additional 10 percent interest in APLNG increasing our ownership to 47.5 percent.

Also in the first quarter, we completed the divestiture of our subsidiaries that held our Indonesia assets and operations.

Production from the disposed assets averaged approximately 33 MBOED in the three-months ended March 31, 2022.

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.

ConocoPhillips 2023 10-K

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Net Income (Loss) ($MM)

$ (13) (51) (107)

The Other International segment includes interests in Colombia as well as contingencies associated with prior operations in other countries.

Earnings from our Other International operations improved $56 million in 2022, compared with 2021, primarily due to the absence of a $137 million after-tax loss on divestiture related to our Argentina exploration interests, partially offset by higher taxes related to legal settlements in 2022.

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

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2023 2022 2021

Net Income (Loss) Attributable to ConocoPhillips

Net Income (Loss)

Net interest expense $ (360) (600) (801)

Corporate general and administrative expenses (244) (317) (200)

Corporate G&A expenses (357) (244) (317)

Technology (34) 32 25

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

Net interest expense improved $201 million in 2022, compared with 2021, primarily due to higher interest income as well as lower interest expenses as a result of our debt reduction transactions.

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.

Corporate G&A expenses include compensation programs and staff costs.

These expenses decreased by $73 million in 2022 compared with 2021, primarily due to the absence of restructuring expenses associated with our Concho acquisition, partially offset by mark-to-market adjustments associated with certain compensation programs.

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 investment in new technologies or businesses, as well as licensing revenues.

Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery as well as LNG.

Other income (expense) ("Other") includes certain corporate tax-related items, foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense.

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 a gain of $251 million on our CVE common shares in 2022, compared with a $1,040 million gain in 2021.

Earnings in "Other" also decreased due to a $101 million tax impact associated with the disposition of our Indonesia assets and higher legal accruals of $81 million.

Offsetting the decreases to earnings in "Other" include a $474 million federal tax benefit associated with the closing of the 2017 audit of our U.S.

federal income tax return, the absence of a release of a $92 million deferred tax asset associated with prior dispositions and recognizing an after-tax gain of $62 million associated with the debt restructuring transactions.

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.

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

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

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.

• 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.

ConocoPhillips 2023 10-K

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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 2022, the primary uses of our available cash were $10.2 billion to support our ongoing capital expenditures and investments program, $9.3 billion to repurchase common stock, $5.7 billion to pay the ordinary dividend and VROC, $3.4 billion to reduce debt through refinancing transactions and retirements and $2.6 billion net purchases of investments.

In 2022, cash and cash equivalents increased by over $1.4 billion to $6.5 billion.

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.

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.

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Operating Activities

Cash provided by operating activities continued to increase in 2022 totaling $28.3 billion, compared with $17.0 billion for 2021, and $4.8 billion for 2020.

The increase in cash provided by operating activities from 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.

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.

The increase in cash from 2021 compared to 2020 is primarily due to higher realized commodity prices and higher sales volumes, mostly resulting from our acquisition of Concho.

The increase was partly offset by the $0.8 billion in settlement of oil and gas hedging positions acquired from Concho and approximately $0.4 billion of transaction and restructuring costs.

Our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs.

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Capital Resources and Liquidity

The level of absolute production volumes, as well as product and location mix, impacts our 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.

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and the addition of proved reserves through exploratory success and their timely and cost-effective development.

While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

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 proved reserves generally increase as prices rise and decrease as prices decline.

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.

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Investing Activities

In 2022, we invested $10.2 billion in capital expenditures a nd investments;

$2.1 billion of which was acquisition capital for the additional 10 percent interest in APLNG, certain Lower 48 assets and the payments toward our investment in QG8.

The remaining $8.1 billion funded our operating capital program inclusive of growth in the Lower 48 segment through the integration of Concho and Shell Permian assets.

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.

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 2022, we completed the monetization of our investment in CVE common shares that we began in May 2021.

By the end of the first quarter of 2022, we fully divested of our investment, recognizing proceeds of $1.4 billion and directing proceeds toward our existing share repurchase program.

Since inception, we generated total proceeds of $2.5 billion.

Other proceeds from dispositions received in the current year include our divestitures in Asia Pacific and Lower 48 segments for approximately $1.5 billion after customary adjustments and $500 million in contingent payments associated with prior divestitures.

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.

S ee 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.

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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 and $1.1 billion from sales of our investment in CVE common shares and $244 million of contingent payments related to dispositions completed before 2021.

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 .

In 2020, proceeds from asset sales were $1.3 billion.

We received cash proceeds of $765 million for the divestiture of our Australia-West assets and operations.

We also received proceeds of $359 million and $184 million from the sale of our Niobrara interests and Waddell Ranch interests in the Lower 48, respectively.

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;

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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 .

ConocoPhillips 2023 10-K

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Financing Activities

In February 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 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.

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.

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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 the redetermination prior to its expiration date.

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).

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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.

Our debt balance at December 31, 2022 was $16.6 billion compa red with $19.9 billion at December 31, 2021.

The current portion of debt, including payments for finance leas es, is $0.4 billion.

In aggregate, these transactions along with naturally maturing debt, reduced the company's total debt by $3.3 billion.

The refinancing facilitates our ability to achieve our previously announced $5 billion debt reduction target by the end of 2026 while also reducing the company's annual cash interest expense.

In December 2023, Fitch affirmed our long-term credit ratings.

The current credit ratings on our long-term debt are:

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" A2 " with a " stable " outlook

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

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.

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

Our debt balance at December 31, 2022, was $16.6 billion, a decrease of $3.3 billion from the balance at December 31, 2021 of $19.9 billion.

As part of our objective to maintain a strong balance sheet, we announced in 2021 our intention to reduce our total debt by $5 billion by the end of 2026.

In 2022, we executed concurrent debt refinancing transactions, repurchased existing notes and retired floating rate notes upon natural maturity, that in aggregate reduced the company's total debt by $3.3 billion and progressed the achievement of our debt reduction target while also lowering our annual cash interest expense and extending the weighted average maturity of our debt portfolio.

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 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.

S e e 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.

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Our 2023 total capital returned was $11 billion.

Consistent with our commitment to deliver value to shareholders, in 2022, we paid ordinary dividends of $1.89 per common share and VROC payments of $2.60 per common share.

This was an increase over 2021 and 2020, when we paid only ordinary dividends of $1.75 and $1.69 per common share, respectively.

In February 2023, we declared a first quarter ordinary dividend of $0.51 cents per share and a VROC of $0.60 cents per share.

The ordinary dividend of $0.51 cents per share is payable March 1, 2023, to shareholders of record on February 14, 2023.

The VROC of $0.60 cents per share is payable April 14, 2023, to shareholders of record on March 29, 2023.

The ordinary dividend and VROC are subject to numerous considerations and will be determined and approved each quarter by the Board of Directors.

If approved, we expect to announce the VROC when we announce our ordinary dividend, but the quarterly payouts will be staggered from the ordinary dividend and paid in the subsequent quarter, resulting in up to eight cash distributions throughout the year.

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.

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Capital Program* $ 11,248 10,159 5,324

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

* 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:

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

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

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

• Development, exploration and appraisal activities across assets in Norway.

• Continued development and exploration activities in Malaysia and China.

• Acquisition capital associated with additional interest in APLNG and certain Lower 48 assets as well as the payment for our investment in QG8.

• 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

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Net Income (Loss) 10,957

Net Income (Loss) Attributable to ConocoPhillips 18,680

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

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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.

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

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• 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.

We did not incur costs related to this regulation in 2022.

Supreme Court decision in Massachusetts v.

EPA , 549 U.S.

497, 127 S.Ct.

1438 (2007), confirmed that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed.

17004 (April 2, 2010)), and the EPA’s and U.S.

Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

EPA’s announcement on January 14, 2015, outlining a series of steps it plans to take to address methane and smog-forming volatile organic compound emissions from the oil and gas industry.

The total cost of compliance related to this regulation in 2023 was approximately $3.5 million (net share before-tax).

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 2022 were fees of approximately $36 million (net share before-tax).

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).

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administration set a new target on April 22, 2021 of a 50 to 52 percent reduction in GHG emissions from 2005 levels in 2030.

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.

ConocoPhillips 2023 10-K

Capital Resources and Liquidity

In the U.S., the Council on Environmental Quality's April 19, 2022 revised regulations and January 9, 2023 National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions and Climate Change for implementing the National Environmental Policy Act (NEPA) require federal agencies to evaluate, among other things, the direct, indirect, and cumulative effects of proposed projects subject to federal authorization, including a project's GHG emissions and potential climate change impact.

The new NEPA regulations may result in longer agency review time or difficulty obtaining federal approval for development projects in our industry.

Furthermore, additional regulations are forthcoming at the federal and state levels with respect to GHG emissions, including EPA’s November 2022 supplemental proposal to strengthen methane emissions standards for new oil and gas facilities and establishing first-time presumptive standards for existing oil and gas facilities, as well as BLM’s November 2022 proposed regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases.

Such regulations, when finalized, may result in the creation of additional costs in the form of taxes, royalty payments, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances.

We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.

• 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.

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.

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• 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.

ConocoPhillips 2022 10-K

Capital Resources and Liquidity

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

Our current Climate Risk Strategy and actions for our oil and gas operations are aligned with the aims of the Paris Agreement while being responsive to shareholder interests for long-term value and competitive returns and is also aligned with our Triple Mandate to responsibly meet energy transition pathway demand, deliver competitive returns on and of capital and achieve our net-zero operational emissions ambition.

In 2020 we became the first U.S.-based oil and gas company to adopt a Paris-aligned climate-risk strategy with an ambition to become a net-zero company for operational (Scope 1 and 2) emissions by 2050.

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.

In early 2022, we published our plan for the Net-Zero Energy Transition (the 'Plan'), to outline 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 our plan include:

• Maintaining a resilient asset portfolio focused on resources with the low cost of supply and low greenhouse gas intensity needed to remain viable in any scenario.

• Setting emissions-reduction targets over the near, medium and long terms for Scope 1 and 2 operational emissions, methane emissions intensity and flaring.

• Expanding policy advocacy beyond carbon pricing to include demand-side policy and regulatory action such as direct federal regulation of methane, advocating for alternative transportation and power generation, and national policy recommendations on natural gas across the value chain.

• Leveraging our assets and capabilities to develop low-carbon technologies and identify emerging business opportunities.

• Tracking and responding to the transition through use of scenario planning to understand alternative pathways and test the resilience of our strategy.

• Continuing capital discipline by incorporating scenario planning and a cost of carbon into our capital allocation decisions.

Our Plan also recognizes the importance of reducing society’s end-use emissions to meet global climate goals.

As an upstream producer, we do not control how the commodities we sell into global markets are converted into different energy products or selected for use by consumers.

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.

ConocoPhillips 2023 10-K

Capital Resources and Liquidity

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.

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

We continued to refine our Paris-aligned climate risk strategy, joined the Oil and Gas Methane Partnership (OGMP) 2.0 Initiative and set a new near-zero 2030 methane emissions intensity target of approximately 0.15 percent of gas produced.

• 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 successful ly execute on our energy transition plans i s subject to a number of risks and un certainties and may be costly to achieve.

See Item 1A .

Risk Factors — O ur 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 .

ConocoPhillips 2023 10-K

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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 $1.8 billion is primarily concentrated in Canada and Alaska.

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.

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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 co-venturer approvals, the timing of which is ultimately beyond our control.

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.

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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 12-month average prices and current costs.

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.

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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 engages third party valuation experts in preparing fair value estimates.

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.

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Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends.

You can often identify our forward-looking statements by the words “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “intend,” “goal,” “guidance,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.

You can often identify our forward-looking statements by the words “ ambition ,” “ anticipate ,” “ believe ,” “ budget ,” “ continue ,” “ could ,” “ effort ,” “ estimate ,” “ expect ,” “ forecast ,” “ intend ,” “ goal ,” “ guidance ,” “ 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.

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• Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels.

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

security threats on facilities and infrastructure;

a public health crisis;

the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries;

or the resulting company or third-party actions in response to such changes.

• The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments.

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• Unexpected changes in costs, inflationary pressures or technical requirements for constructing, modifying or operating E&P facilities.

• Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal.

• Significant operational or investment changes imposed by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce GHG emissions.

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• Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future E&P and LNG development in a timely manner (if at all) or on budget.

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

• 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;

cybersecurity threats and information technology failures, constraints or disruptions.

• Changes in international monetary conditions and foreign currency exchange rate fluctuations.

• Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as aluminum and steel) used in the operation of our business, including any sanctions imposed as a result of any ongoing military conflict, including the conflict between Russia and Ukraine.

• Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs, carbon and any materials or products (such as aluminum and steel) used in the operation of our business, including any sanctions imposed as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.

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

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expropriation of assets;

changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and NGLs pricing, including the imposition of price caps;

changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and NGLs and carbon pricing, including the imposition of price caps;

regulation or taxation;

and other political, economic or diplomatic developments, including as a result of any ongoing military conflict, including the conflict between Russia and Ukraine.

and other political, economic or diplomatic developments, including as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.

• Volatility in the commodity futures markets.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis