ConocoPhillips Leadership Assessment: 2022 MD&A Analysis

Management's Discussion and Analysis

Table of Contents

Item 7. Management's Discussion and Analysis of Financial Condition and

Results of Operations

Management's Discussion and Analysis is the company's analysis of its financial performance and of significant trends 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 company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 63.

The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

Business Environment and Executive Overview

ConocoPhillips is one of the world's leading E&P companies based on both production and reserves with operations and activities in 13 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; LNG developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas, at December 31, 2022, we employed approximately 9,500 people worldwide and had total assets of $94 billion.

Overview

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. We believe ConocoPhillips will continue to play an essential role by executing on three objectives: responsibly meeting energy transition pathway demand, delivering competitive returns on and of capital and achieving our net-zero operational emissions ambition. We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders.

Our value proposition to deliver competitive returns to stockholders through price cycles is guided by foundational principles that support our Triple Mandate. 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. See Note 9.

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Management's Discussion and Analysis

Table of Contents

Total company production in 2022 was 1,738 MBOED, yielding cash provided by operating activities of $28.3 billion. We invested $10.2 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of approximately $15.0 billion through our ordinary dividend, share repurchases and our VROC. For 2022, we returned $2.4 billion from our ordinary dividend, which included an increase from 46 cents per share to 51 cents per share, effective in December. We also returned $3.3 billion to shareholders from the VROC in 2022. 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. See Note 5. In total for 2022, we returned $9.3 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, 2022, we have repurchased $23.4 billion of the $45 billion authorized share repurchase program.

In February 2023, we announced our 2023 planned return of capital to shareholders of $11 billion through our three-tier return of capital framework. We also declared a first quarter ordinary dividend of $0.51 cents per share and a VROC of $0.60 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. See Note 3. 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.

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ConocoPhillips 2022 10-K

Management's Discussion and Analysis

Key Operating and Financial Summary

Significant items during 2022 and recent announcements included the following:

•Generated cash provided by operating activities of $28.3 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.

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.

•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 ended the year with cash and cash equivalents and restricted cash of $6.7 billion and short-term investments of $2.8 billion, maintaining balance sheet strength.

•Peer leading distributions. We believe in delivering value to our shareholders via our three-tiered return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and our VROC. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 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. See Note 5. Our combined dividends and share repurchases of $15 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 2023, we announced our 2023 planned return of capital to shareholders of $11 billion through our three-tier return of capital framework. See "Item 1A-Risk Factors Our ability to execute our capital return program is subject to certain considerations."

•Disciplined investments. Our goal is to achieve strong free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to 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.

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Management's Discussion and Analysis

◦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. 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. In setting our capital plans, we exercise a rigorous approach that evaluates projects using these cost of supply criteria, which we believe will lead to value maximization and cash flow expansion using an optimized investment pace, not production growth for growth's sake. Our cash allocation priorities call for the investment of sufficient capital to sustain production and provide returns of capital to shareholders.

◦Control our costs. Controlling 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.

◦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. See Note 4.

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. See Note 3.

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

▪Acquire interest in existing or new fields.

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

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

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

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.

In the three years ended December 31, 2022, our reserve replacement was 180 percent. Our organic reserve replacement during the three years ended December 31, 2022, which excludes a net increase of 1,103 MMBOE related to sales and purchases, was 114 percent. See "Supplementary Data - Oil and Gas Operations" for more information.

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

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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. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors through to executive leadership and business unit managers.

In October 2020, we became the first U.S.-based oil and natural gas company to adopt a Paris-aligned climate risk framework that includes an ambition to achieve net-zero Scope 1 and 2 emissions on a gross operated and net equity basis by 2050. We believe that this framework, combined with our success in meeting the business objectives set by our Triple Mandate, represents the most effective way for us to sustainably contribute to society's transition to a low-carbon economy. In 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. The energy transition will likely be complex, evolving over multiple decades with many possible pathways and uncertainties. By following our Triple Mandate, we intend to meet this challenge in an economically viable, accountable and actionable way that creates long-term value for our stakeholders. For more information on our commitment to responsible and reliable ESG performance through the energy transition, see "Contingencies-Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.

Commodity Prices

Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but not limited to global economic health, supply 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. 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.

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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.

Outlook

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.

Operating Segments

We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.

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

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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ConocoPhillips 2022 10-K

Results of Operations Table of Contents

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons between 2022 and 2021. For discussion of year-to-year comparisons between 2021 and 2020, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2021 10-K.

Consolidated Results

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

Millions of Dollars

Years Ended December 31202220212020

Alaska$2,352 1,386 (719)

Lower 4811,015 4,932 (1,122)

Canada714 458 (326)

Europe, Middle East and North Africa2,244 1,167 448

Asia Pacific2,736 453 962

Other International(51)(107)(64)

Corporate and Other(330)(210)(1,880)

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. See Note 3.

•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. See Note 3.

•Absence of a $682 million after-tax impairment of our APLNG investment included within our Asia Pacific segment. See Note 7.

•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. See Note 3.

•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. See Note 12.

•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. See Note 9.

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. See Note 5.

•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. See Note 11.

•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. See Note 6.

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Results of Operations Table of Contents

Income Statement Analysis

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

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. See Note 3.

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. See Note 3.

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. See Note 3.

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. See Note 5. 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. See Note 9.

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

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ConocoPhillips 2022 10-K

Results of Operations Table of Contents

Summary Operating Statistics

202220212020

Average Net Production

Crude oil (MBD)

Consolidated Operations885 816 555

Equity affiliates13 13 13

Total crude oil898 829 568

Natural gas liquids (MBD)

Consolidated Operations244 134 97

Equity affiliates8 8 8

Total natural gas liquids252 142 105

Bitumen (MBD)66 69 55

Natural gas (MMCFD)

Consolidated Operations1,939 2,109 1,339

Equity affiliates1,191 1,053 1,055

Total natural gas3,130 3,162 2,394

Total Production (MBOED)

1,738 1,567 1,127

Dollars Per Unit

Average Sales Prices

Crude oil (per bbl)

Consolidated Operations$97.23 67.61 39.56

Equity affiliates97.31 69.45 39.02

Total crude oil97.23 67.64 39.54

Natural gas liquids (per bbl)

Consolidated Operations35.67 31.04 12.90

Equity affiliates61.22 54.16 32.69

Total natural gas liquids36.50 32.45 14.61

Bitumen (per bbl)55.56 37.52 8.02

Natural gas (per mcf)

Consolidated Operations10.56 6.00 3.17

Equity affiliates10.67 5.31 3.71

Total natural gas10.60 5.77 3.41

Millions of Dollars

Worldwide Exploration Expenses

General and administrative; geological and geophysical, lease rental, and other$224 300 374

Leasehold impairment89 10 868

Dry holes251 34 215

Total Exploration Expenses$564 344 1,457

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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. At December 31, 2022, 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. See Note 3.

•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. See Note 3.

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.

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Results of Operations Table of Contents

Segment Results

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

Alaska

202220212020

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

$2,352 1,386 (719)

Average Net Production

Crude oil (MBD)177 178 181

Natural gas liquids (MBD)17 16 16

Natural gas (MMCFD)34 16 10

Total Production (MBOED)

200 197 198

Average Sales Prices

Crude oil ($ per bbl)$101.72 69.87 42.12

Natural gas ($ per mcf)3.64 2.81 2.91

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In 2022, Alaska contributed 16 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Alaska reported earnings of $2,352 million in 2022, compared with earnings of $1,386 million in 2021. 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.

Production

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.

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Results of Operations Table of Contents

Lower 48

202220212020

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

$11,015 4,932 (1,122)

Average Net Production

Crude oil (MBD)534 447 213

Natural gas liquids (MBD)*221 110 74

Natural gas (MMCFD)*1,402 1,340 585

Total Production (MBOED)

989 780 385

Average Sales Prices

Crude oil ($ per bbl)$94.46 66.12 35.17

Natural gas liquids ($ per bbl)35.36 30.63 12.13

Natural gas ($ per mcf)5.92 4.38 1.65

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

The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico and commercial operations. During 2022, the Lower 48 contributed 64 percent of our consolidated liquids production and 72 percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Lower 48 reported earnings of $11,015 million in 2022, compared with earnings of $4,932 million in 2021. Earnings were positively impacted by:

•Higher realized prices.

•Higher sales volumes primarily related to our Shell Permian Acquisition. See Note 3.

•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.

Production

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. See Note 3.

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

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. See Note 3.

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ConocoPhillips 2022 10-K

Results of Operations Table of Contents

Canada

202220212020

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

$714 458 (326)

Average Net Production

Crude oil (MBD)6 8 6

Natural gas liquids (MBD)3 4 2

Bitumen (MBD)66 69 55

Natural gas (MMCFD)61 80 40

Total Production (MBOED)

85 94 70

Average Sales Prices

Crude oil ($ per bbl)$79.94 56.38 23.57

Natural gas liquids ($ per bbl)37.70 31.18 5.41

Bitumen ($ per bbl)55.56 37.52 8.02

Natural gas ($ per mcf)3.62 2.54 1.21

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

Canada operations reported earnings of $714 million in 2022 compared with earnings of $458 million in 2021. 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. See Note 6.

•Lower sales volumes.

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

Production

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.

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44

Results of Operations Table of Contents

Europe, Middle East and North Africa

202220212020

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

$2,244 1,167 448

Consolidated Operations

Average Net Production

Crude oil (MBD)107 118 86

Natural gas liquids (MBD)3 4 4

Natural gas (MMCFD)328 313 275

Total Production (MBOED)

165 175 136

Average Sales Prices

Crude oil ($ per bbl)$99.20 68.97 43.30

Natural gas liquids ($ per bbl)54.52 43.97 23.27

Natural gas ($ per mcf)33.39 13.27 3.23

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 2022, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

The Europe, Middle East and North Africa segment reported earnings of $2,244 million in 2022 compared with earnings of $1,167 million in 2021. 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.

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.

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. 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.

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ConocoPhillips 2022 10-K

Results of Operations Table of Contents

Asia Pacific

202220212020

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

$2,736 453 962

Consolidated Operations

Average Net Production

Crude oil (MBD)61 65 69

Natural gas liquids (MBD)- - 1

Natural gas (MMCFD)114 360 429

Total Production (MBOED)

80 125 141

Average Sales Prices

Crude oil ($ per bbl)$105.52 70.36 42.84

Natural gas liquids ($ per bbl)- - 33.21

Natural gas ($ per mcf)5.84 6.56 5.39

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

Asia Pacific reported earnings of $2,736 million in 2022, compared with $453 million in 2021. 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. See Note 3.

•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.

Consolidated Production

Average consolidated production decreased 45 MBOED in 2022, compared with 2021. The decrease was primarily due to:

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

•Normal field decline.

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. See Note 3.

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46

Results of Operations Table of Contents

Other International

202220212020

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

$(51)(107)(64)

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.

Corporate and Other

Millions of Dollars

202220212020

Net Income (Loss) Attributable to ConocoPhillips

Net interest expense$(600)(801)(662)

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

Technology32 25 (26)

Other income (expense)482 883 (992)

$(330)(210)(1,880)

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. See Note 9.

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. 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. Earnings in "Other" decreased by $401 million in 2022 compared with 2021. 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.

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ConocoPhillips 2022 10-K

Capital Resources and Liquidity

Capital Resources and Liquidity

Financial Indicators

Millions of DollarsExcept as Indicated

202220212020

Net cash provided by operating activities$28,314 16,996 4,802

Cash and cash equivalents6,458 5,028 2,991

Short-term investments2,785 446 3,609

Short-term debt417 1,200 619

Total debt16,643 19,934 15,369

Total equity48,003 45,406 29,849

Percent of total debt to capital*26 %31 34

Percent of floating-rate debt to total debt2 %4 7

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, proceeds from asset sales, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement. In 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.

At December 31, 2022, we had cash and cash equivalents of $6.5 billion, short-term investments of $2.8 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $14.8 billion of liquidity. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the "Significant Changes in Capital" section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments and required debt payments.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities 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. 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. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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48

Capital Resources and Liquidity

The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Full-year production averaged 1,738 MBOED in 2022, an increase of 171 MBOED or 11 percent compared to 2021. First quarter 2023 production is expected to be 1.72 MMBOED to 1.76 MMBOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively 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.

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. Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production. For information on proved reserves, including both developed and undeveloped reserves, see the reserve table disclosures contained in "Supplementary Data - Oil and Gas Operations." See "Item 1A-Risk Factors - Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business."

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

Investing Activities

In 2022, we invested $10.2 billion in capital expenditures and 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. Capital expenditures invested in 2021 and 2020 were $5.3 billion and $4.7 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. See Note 5. 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. See Note 3.

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

In 2021, total proceeds from asset dispositions were $1.7 billion. We received cash proceeds of $250 million from the sale of noncore assets in our Lower 48 segment 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. 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. See Note 3.

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

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ConocoPhillips 2022 10-K

Capital Resources and Liquidity

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 revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to the redetermination prior to its expiration date.

Credit facility borrowings may bear interest at a margin above the Secured Overnight Financing Rate (SOFR). The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

The revolving credit facility supports ConocoPhillips Company's ability to issue up to $5.5 billion of commercial paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at December 31, 2022.

Our debt balance at December 31, 2022 was $16.6 billion compared with $19.9 billion at December 31, 2021. The current portion of debt, including payments for finance leases, is $0.4 billion. 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. 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.

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

•Fitch: "A" with a "stable" outlook

•S&P: "A-" with a "stable" outlook

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

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

We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, upon downgrade of our credit ratings. If our credit ratings are downgraded from their current levels, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At December 31, 2022 and December 31, 2021, we had direct bank letters of credit of $368 million and $337 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Shelf Registration

We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

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50

Capital Resources and Liquidity

Capital Requirements

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. See Note 9.

In February 2023, we announced our 2023 planned return of capital to shareholders of $11 billion through our three-tier return of capital framework. We plan to deliver a compelling, growing ordinary dividend, through-cycle share repurchases and a VROC payment. The VROC provides a flexible tool for meeting our commitment of returning greater than 30 percent of cash from operating activities during periods where commodity prices are meaningfully higher than our planning price range. Our 2022 total capital returned was $15 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.

In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of our common stock to support our plan for future share repurchases. Share repurchases were $9.3 billion, $3.6 billion, and $0.9 billion in 2022, 2021, and 2020, respectively. As of December 31, 2022, share repurchases since the inception of our current program totaled 334.8 million shares and $23.4 billion. Repurchases are made at management's discretion, at prevailing prices, subject to market conditions and other factors.

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

As of December 31, 2022, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $19.2 billion. We expect to fulfill $8.8 billion of these obligations in 2023. These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations of $5.0 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase obligations of $12.7 billion are related to market-based contracts for commodity product purchases with third parties. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

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ConocoPhillips 2022 10-K

Capital Resources and Liquidity

Capital Expenditures and Investments

Millions of Dollars

202220212020

Alaska1,091 982 1,038

Lower 485,630 3,129 1,881

Canada530 203 651

Europe, Middle East and North Africa998 534 600

Asia Pacific1,880 390 384

Other International- 33 121

Corporate and Other30 53 40

Capital Program*10,159 5,324 4,715

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

Our capital expenditures and investments for the three-year period ended December 31, 2022, totaled $20.2 billion. The 2022 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.

2023 Capital Budget

In February 2023, we announced our 2023 operating plan capital is expected to be between $10.7 to $11.3 billion. The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.

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52

Capital Resources and Liquidity

Guarantor Summarized Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, and Burlington Resources LLC with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.

The following tables present summarized financial information for the Obligor Group, as defined below:

•The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.

•Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information.

•Non-Obligated Subsidiaries are excluded from this presentation.

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

Summarized Income Statement Data

Millions of Dollars

2022

Revenues and Other Income$55,630

Income (loss) before income taxes*18,438

Net income (loss)18,680

Net Income (Loss) Attributable to ConocoPhillips18,680

*Includes approximately $9.0 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

Millions of Dollars

December 31, 2022

Current assets$10,766

Amounts due from Non-Obligated Subsidiaries, current1,892

Noncurrent assets79,269

Amounts due from Non-Obligated Subsidiaries, noncurrent6,552

Current liabilities8,201

Amounts due to Non-Obligated Subsidiaries, current3,248

Noncurrent liabilities40,389

Amounts due to Non-Obligated Subsidiaries, noncurrent24,594

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ConocoPhillips 2022 10-K

Capital Resources and Liquidity

Contingencies

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

Legal and Tax Matters

We are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged environmental contamination and damages from historic operations, and climate change. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience, and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 17.

Environmental

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of December 31, 2022, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

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

Expensed environmental costs were $705 million in 2022 and are expected to be approximately $669 million and $727 million in 2023 and 2024, respectively. Capitalized environmental costs were $239 million in 2022 and are expected to be about $276 million and $314 million in 2023 and 2024, respectively.

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

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

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Capital Resources and Liquidity

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

At December 31, 2022, our balance sheet included total accrued environmental costs of $182 million, compared with $187 million at December 31, 2021, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

See Item 1A-Risk Factors - We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations and Note 11 for information on environmental litigation.

Climate Change

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on GHG emissions reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include:

•European Emissions Trading Scheme (ETS), the program through which many of the EU member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2022 was approximately $22 million (net share before-tax).

•U.K. Emissions Trading Scheme, the program with which the U.K. has replaced the ETS. Our cost of compliance with the U.K. ETS in 2022 was approximately $0.6 million (net share before-tax).

•The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity. We did not incur costs related to this regulation in 2022.

•The U.S. 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.

•The U.S. EPA's announcement on March 29, 2010 (published as "Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs," 75 Fed. Reg. 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.

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

•Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon legislation in 2022 were fees of approximately $36 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 $6 million (net share before-tax).

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

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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.

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

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

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

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

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

•The GHG reductions required.

•The price and availability of offsets.

•The amount and allocation of allowances.

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

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

•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.

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Capital Resources and Liquidity

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. 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. This is why we have consistently taken a prominent role in advocating for a well-designed, economy wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include regulatory action, such as support for the direct regulation of methane.

In support of addressing our Scope 1 and 2 emissions, in 2022, 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. Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technologies organization. See Item 1A-Risk Factors - Our ability to successfully execute on our energy transition plans is subject to a number of risks and uncertainties and may be costly to achieve.

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Critical Accounting Estimates

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

Oil and Gas Accounting

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

Property Acquisition Costs

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

At year-end 2022, we held $6.5 billion of net capitalized unproved property costs which consisted primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest. Of this amount, approximately $4.7 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. Management periodically assesses our unproved property for impairment based on the results of exploration and drilling efforts and the outlook for commercialization.

Exploratory Costs

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

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

At year-end 2022, total suspended well costs were $527 million, compared with $660 million at year-end 2021. For additional information on suspended wells, including an aging analysis, see Note 6.

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Proved Reserves

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

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

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

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

The estimation of proved reserves is also important to the income statement because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2022, the net book value of productive PP&E subject to a unit-of-production calculation was approximately $55 billion and the DD&A recorded on these assets in 2022 was approximately $7.3 billion. The estimated proved developed reserves for our consolidated operations were 4.0 billion BOE at the end of 2021 and 3.8 billion BOE at the end of 2022. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, before-tax DD&A in 2022 would have increased by an estimated $808 million.

Business Combination-Valuation of Oil and Gas Properties

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

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

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

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Impairments

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

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

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

Asset Retirement Obligations and Environmental Costs

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

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

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the U.S. at exploration and production sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. See Note 8.

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Projected Benefit Obligations

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

Contingencies

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

Income Taxes

We are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing oil and gas prices). See Note 17.

We regularly assess and, if required, establish accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note 17.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often identify our forward-looking statements by the words "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. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:

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

•Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict, including the 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.

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

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

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

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

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

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

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

•Substantial investment in and development use of, competing or alternative energy sources, including as a result of existing or future environmental rules and regulations.

•The impact of broader societal attention to and efforts to address climate change may impact our access to capital and insurance.

•Potential failures or delays in delivering on our current or future low-carbon strategy, including our inability to develop new technologies.

•The impact of public health crises, including pandemics (such as COVID-19) and epidemics and any related company or government policies or actions.

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ConocoPhillips 2022 10-K

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

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

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

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

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

•Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs 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.

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

•Liability resulting from litigation, including litigation directly or indirectly related to the transaction with Concho Resources Inc., or our failure to comply with applicable laws and regulations.

•General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and NGLs 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.

•Volatility in the commodity futures markets.

•Changes in tax and other laws, regulations (including alternative energy mandates) or royalty rules applicable to our business.

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

•Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets or investment sentiment, including as a result of increased societal attention to and efforts to address climate change.

•Our inability to execute, or delays in the completion of, any asset dispositions or acquisitions we elect to pursue.

•Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for pending or future asset dispositions or acquisitions, or that such approvals may require modification to the terms of the transactions or the operation of our remaining business.

•Potential disruption of our operations as a result of pending or future asset dispositions or acquisitions, including the diversion of management time and attention.

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

•The operation and financing of our joint ventures.

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

•Our inability to realize anticipated cost savings and capital expenditure reductions.

•The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or involuntary, required to mitigate this physical constraint.

•The risk that we will be unable to retain and hire key personnel.

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

•The factors generally described in Part I-Item 1A in this 2022 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

ConocoPhillips 2022 10-K