Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition," “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 47**.

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

Business Environment and Executive Overview

ConocoPhillips is one of the world’s leading E&P companies based on production and reserves, with operations and activities in 13 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at March 31, 2024, we employed approximately 10,000 people worldwide and had total assets of $95 billion.

Overview

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

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

Our Triple Mandate and our foundational principles guide our differential value proposition to deliver competitive returns to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance.

In May, we reconfirmed our 2024 planned return of capital to shareholders of at least $9 billion through our three-tier return of capital framework. We also declared a second quarter ordinary dividend of $0.58 per share and a VROC payment of $0.20 per share.

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Management’s Discussion and Analysis			Table of Contents

Operationally, we remain focused on safely executing the business while also progressing key strategic initiatives. At Willow, project activity continued to ramp up during our first major winter construction season following FID late last year. In the Lower 48, we continued to execute our program, focusing on operating and capital efficiencies. Internationally, after reaching first production in projects in Canada, Norway and China at the end of 2023, we see production growth as those projects continued to ramp up through additional wells online. Also in March 2024, we received a license extension until 2045 on the partner-operated Heidrun field in Norway.

Production was 1,902 MBOED in the first quarter of 2024, an increase of 110 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, first-quarter 2024 production increased by 43 MBOED or two percent from the same period a year ago.

First-quarter 2024 production resulted in $5.0 billion of cash provided by operating activities. We also returned $1.3 billion to shareholders through share repurchases and $0.9 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents, restricted cash and short-term investments totaling $6.3 billion and long-term investments in debt securities of $1.1 billion.

Also in the first quarter of 2024, we re-invested $2.9 billion into the business in the form of capital expenditures and investments, with over half of the expenditures related to flexible, short-cycle unconventional plays in the Lower 48 segment, where our production has access to both domestic and export markets.

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Management’s Discussion and Analysis			Table of Contents

Business Environment

Commodity prices are the most significant factor impacting our profitability and related returns on and of capital to our shareholders. Dynamics that could influence world energy markets and commodity prices include, but are not limited to, global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tax regulations, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial, operational and ESG priorities that underpin our value proposition.

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

Brent crude oil prices averaged $83.24 per barrel in the first quarter of 2024, an increase of 2 percent compared with $81.27 per barrel in the first quarter of 2023. WTI at Cushing crude oil prices averaged $76.96 per barrel in the first quarter of 2024, an increase of 1 percent compared with $76.13 per barrel in the first quarter of 2023. Oil prices in the first quarter of 2024 were supported by global oil demand growth, voluntary production cuts by OPEC Plus members and geopolitical risks impacting trade flows.

Henry Hub natural gas prices averaged $2.25 per MMBTU in the first quarter of 2024, a decrease of 35 percent compared with $3.44 per MMBTU in the first quarter of 2023. Henry Hub prices decreased due to mild winter weather resulting in excess North American natural gas storage levels.

Our realized bitumen price averaged $44.30 per barrel in the first quarter of 2024, an increase of 50 percent compared with $29.49 per barrel in the first quarter of 2023. The increase in the first quarter of 2024 was driven by narrowing WCS differentials as a result of improving heavy oil demand in Asia and a more favorable sales mix with a lower proportion sold by rail. We continue to optimize bitumen price realizations through diluent recovery unit operating improvements as well as blending and transportation strategies.

For the first quarter of 2024, our total average realized price was $56.60 per BOE compared with $60.86 per BOE in the first quarter of 2023.

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Key Operating and Financial Summary

Significant items during the first quarter of 2024 and recent announcements included the following:

• Delivered total company production of 1,902 MBOED;

• Produced 1,046 MBOED in the Lower 48, including 736 MBOED from Permian, 197 MBOED from the Eagle Ford and 96 MBOED from the Bakken;

• Executed a successful first major winter construction season at Willow in Alaska and advanced development of LNG projects in the U.S. and Qatar;

• Continued ramp-up from recent international project startups including Surmont Pad 267 in Canada, several sub-sea tiebacks in Norway and Bohai Phase 4B in China;

• Progressed Montney development program following startup of the second phase of the company's central processing facility in Canada, resulting in record production for the asset;

*•*Achieved 1,000th LNG cargo export milestone at Australia Pacific LNG Pty Ltd. in April;

• Distributed $2.2 billion to shareholders through a three-tier framework, including $1.3 billion through share repurchases and $0.9 billion through the ordinary dividend and VROC;

• Retired debt of $0.5 billion at maturity; and

• Ended the quarter with cash, cash equivalents, restricted cash and short-term investments of $6.3 billion and long-term investments in debt securities of $1.1 billion.

Outlook

Production

Second quarter 2024 production is expected to be 1.91 to 1.95 MMBOED.

All full-year guidance items remain unchanged.

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Results of Operations			Table of Contents

Results of Operations

Unless otherwise indicated, discussion of consolidated results for the three-month period ended March 31, 2024, is based on a comparison with the corresponding period of 2023.

Consolidated Results

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

			Millions of Dollars
			Three Months Ended March 31
			2024			2023
Alaska			$	346		416
Lower 48			1,381			1,852
Canada			180			6
Europe, Middle East and North Africa			304			365
Asia Pacific			512			522
Other International			(1)			1
Corporate and Other			(171)			(242)
Net income (loss)			$	2,551		2,920

Net income (loss) in the first quarter of 2024 decreased $369 million. First quarter earnings were negatively impacted by:

• Lower realized gas and NGL commodity prices.

• Lower commercial performance and timing.

• Higher DD&A expenses due to higher rates across our segments and higher volumes primarily in our Canada segment resulting from our acquisition of additional working interest in Surmont, which closed in October 2023. See Note 3.

• Higher production and operating expenses primarily driven by higher production volumes associated with our acquisition of additional working interest in Surmont in addition to higher expenses in our Lower 48 and Alaska segments due to higher lease operating expenses and well work activities of approximately $55 million and higher transportation related charges of approximately $44 million. See Note 3.

• Lower LNG sales prices, reflected in equity in earnings of affiliates.

Offsets to the earnings decreases include:

• Higher sales volumes driven primarily by our Surmont acquisition in our Canada segment. See Note 3.

• Higher realized bitumen and crude oil prices.

• A tax benefit of $76 million recorded in the first quarter of 2024 associated with deepwater investment tax incentive for Malaysia Blocks J and G. See Note 19.

See the “Segment Results” section for additional information.

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Income Statement Analysis

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

Sales and other operating revenues decreased $963 million, primarily due to lower realized natural gas and NGL prices, partially offset by higher sales volumes resulting from our acquisition of additional working interest in Surmont in our Canada segment, which closed in October 2023, and higher realized bitumen and crude prices. See Note 3.

Equity in earnings of affiliates decreased $78 million, due to lower earnings driven by lower LNG prices*.*

Purchased commodities decreased $804 million, primarily due to lower gas prices partially offset by higher purchased volumes across all commodities.

Production and operating expenses increased $236 million, due to higher production volumes resulting from our acquisition of additional working interest in Surmont in our Canada segment in addition to higher expenses in our Lower 48 and Alaska segments due to higher lease operating expenses and well work activities of approximately $55 million and higher transportation related charges of approximately $44 million. See Note 3.

DD&A expenses increased $269 million, mainly due to higher rates across our segments as well as higher volumes primarily in our Canada segment resulting from the acquisition of additional working interest in Surmont. See Note 3.

See Note 19—Income Taxes for information regarding our Income tax provision (benefit) and effective tax rate.

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Results of Operations			Table of Contents

Summary Operating Statistics

			Three Months Ended March 31
			2024			2023
Average Net Production
Crude oil (MBD)
Consolidated operations			928			926
Equity affiliates			16			11
Total crude oil			944			937
Natural gas liquids (MBD)
Consolidated operations			271			264
Equity affiliates			8			7
Total natural gas liquids			279			271
Bitumen (MBD)			129			69
Natural gas (MMCFD)
Consolidated operations			2,035			1,922
Equity affiliates			1,267			1,166
Total natural gas			3,302			3,088
Total Production (MBOED)			1,902			1,792

			Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations			$	78.67		77.60
Equity affiliates			76.94			80.97
Total crude oil			78.64			77.65
Natural gas liquids (per bbl)
Consolidated operations			23.35			24.97
Equity affiliates			52.09			57.71
Total natural gas liquids			24.25			25.84
Bitumen (per bbl)			44.30			29.49
Natural gas (per MCF)
Consolidated operations			2.91			5.65
Equity affiliates			8.26			9.95
Total natural gas			5.02			7.30

			Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental and other			$	93		70
Leasehold impairment			—			19
Dry holes			19			49
			$	112		138

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

Total production in the first quarter of 2024 was 1,902 MBOED, an increase of 110 MBOED or six percent. Production increases include:

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

• Our Surmont acquisition, which closed in October 2023.

Production increases were partially offset by normal field decline.

After adjusting for impacts from closed acquisitions and dispositions, first-quarter 2024 production increased by 43 MBOED or two percent from the same period a year ago.

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Results of Operations			Table of Contents

Segment Results

Unless otherwise indicated, discussion of segment results for the three-month period ended March 31, 2024, is based on a comparison with the corresponding period of 2023 and are shown after-tax.

Alaska

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	346		416
Average Net Production
Crude oil (MBD)			180			179
Natural gas liquids (MBD)			14			18
Natural gas (MMCFD)			42			42
Total Production (MBOED)			201			204
Average Sales Prices
Crude oil ($ per bbl)			$	83.59		82.22
Natural gas ($ per MCF)			3.91			4.58

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of March 31, 2024, Alaska contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Earnings from Alaska decreased $70 million in the first quarter of 2024. Decreases to earnings include:

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

• Higher production and operating expenses primarily due to higher well work activity of $13 million and higher transportation related costs of $11 million.

• Higher exploration expenses primarily due to increased seismic work of $26 million.

Offsets to the earnings decreases were primarily driven by the absence of first-quarter 2023 dry hole expenses.

Production

Average production decreased 3 MBOED in the first quarter of 2024. Decreases to production were primarily due to normal field decline.

Production decreases were partly offset by new wells online and improved performance at our Western North Slope and Greater Kuparuk Area assets.

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Lower 48

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	1,381		1,852
Average Net Production
Crude oil (MBD)			553			561
Natural gas liquids (MBD)			247			239
Natural gas (MMCFD)			1,479			1,418
Total Production (MBOED)			1,046			1,036
Average Sales Prices
Crude oil ($ per bbl)			$	75.51		74.36
Natural gas liquids ($ per bbl)			22.67			24.58
Natural gas ($ per MCF)			1.57			2.92

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties in the Gulf of Mexico. As of March 31, 2024, the Lower 48 contributed 60 percent of our consolidated liquids production and 73 percent of our consolidated natural gas production.

Net Income (Loss)

Earnings from the Lower 48 decreased $471 million in the first quarter of 2024. Decreases to earnings include:

• Lower realized natural gas and NGL prices.

• Lower commercial performance and timing.

• Higher production and operating expenses primarily due to increased lease operating expenses of $36 million and increased transportation related costs of $31 million.

• Higher DD&A expenses primarily due to higher rates driven from increased capital additions.

Offsets to the earnings decrease were primarily driven by higher natural gas and NGL sales volumes.

Production

Average production increased 10 MBOED in the first quarter of 2024. Increases to production were primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.

Production increases were partly offset by normal field decline.

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Results of Operations			Table of Contents

Canada

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	180		6
Average Net Production
Crude oil (MBD)			18			6
Natural gas liquids (MBD)			6			3
Bitumen (MBD)			129			69
Natural gas (MMCFD)			100			64
Total Production (MBOED)			170			89
Average Sales Prices
Crude oil ($ per bbl)			$	64.40		65.07
Natural gas liquids ($ per bbl)			35.47			29.02
Bitumen ($ per bbl)			44.30			29.49
Natural gas ($ per MCF)*			1.01			4.64

*Average sales prices include unutilized transportation costs.

Our Canadian operations consist of the Surmont oil sands development in Alberta and the Montney unconventional play in British Columbia. As of March 31, 2024, Canada contributed 12 percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Earnings from Canada increased $174 million in the first quarter of 2024. Increases to earnings include:

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

• Higher realized bitumen prices.

Offsets to the earnings increases include:

• Higher production and operating expenses primarily due to higher production volumes as a result of our increased working interest in Surmont. See Note 3.

• Higher DD&A expenses of $51 million primarily due to higher production volumes as a result of our Surmont acquisition, partially offset by lower rates in Surmont.

Production

Average production increased 81 MBOED in the first quarter of 2024. Increases to production include:

• Higher volumes as a result of our increased working interest in Surmont. See Note 3.

• New wells online in the Montney and Surmont.

Production increases were partly offset by normal field decline.

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Europe, Middle East and North Africa

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	304		365
Consolidated Operations
Average Net Production
Crude oil (MBD)			118			117
Natural gas liquids (MBD)			4			4
Natural gas (MMCFD)			358			342
Total Production (MBOED)			182			178
Average Sales Prices
Crude oil ($ per bbl)			$	84.83		83.52
Natural gas liquids ($ per bbl)			46.32			47.91
Natural gas ($ per MCF)			8.81			17.18

Production and sales prices exclude equity affiliates. See Summary Operating Statistics for equity affiliate totals.

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea and the Norwegian Sea, Qatar, Libya and commercial and terminalling operations in the U.K. As of March 31, 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Net Income (Loss)

Earnings from Europe, Middle East and North Africa decreased by $61 million in the first quarter of 2024. Decreases to earnings include:

• Lower realized natural gas prices.

• Lower foreign exchange gains of approximately $19 million related to USD and EUR strengthening against the NOK.

Offsets to the earnings decrease were primarily driven by higher sales volumes.

Consolidated Production

Average consolidated production increased 4 MBOED in the first quarter of 2024. Increases to production were primarily due to new wells online and improved performance in both Norway and Libya.

Production increases were partly offset by normal field decline.

Exploration Activity

In the first quarter of 2024, we charged $18 million before-tax as dry hole expense for the Busta suspended discovery well on license PL782S that was drilled in 2019.

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Results of Operations			Table of Contents

Asia Pacific

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	512		522
Consolidated Operations
Average Net Production
Crude oil (MBD)			59			63
Natural gas (MMCFD)			56			56
Total Production (MBOED)			68			72
Average Sales Prices
Crude oil ($ per bbl)			$	85.05		83.50
Natural gas ($ per MCF)			3.68			4.30

Production and sales prices exclude equity affiliates. See Summary Operating Statistics for equity affiliate totals.

The Asia Pacific segment has operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. As of March 31, 2024, Asia Pacific contributed four percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income (Loss)

Earnings from Asia Pacific decreased $10 million in the first quarter of 2024. Decreases to earnings were primarily driven by lower earnings from equity affiliates due to lower LNG sales prices.

Offsets to the earnings decreases were primarily driven by a $76 million tax benefit associated with a deepwater investment tax incentive for Malaysia Blocks J and G. See Note 19.

Consolidated Production

Average consolidated production decreased 4 MBOED in the first quarter of 2024. Decreases to production were primarily due to normal field decline.

Production decreases were partly offset by Bohai Bay development activity in China.

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Other International

			Three Months Ended March 31
			2024			2023
Net Income (Loss) ($MM)			$	(1)		1

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

Corporate and Other

			Millions of Dollars
			Three Months Ended March 31
			2024			2023
Net Income (Loss)
Net interest expense			$	(93)		(90)
Corporate general and administrative expenses			(105)			(90)
Technology			(24)			6
Other income (expense)			51			(68)
			$	(171)		(242)

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

Corporate G&A expenses include compensation programs and staff costs. Corporate G&A expenses increased $15 million in the first quarter of 2024, primarily due to mark-to-market adjustments associated with certain compensation programs.

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

Other income (expense) or “Other” includes certain consolidating tax-related items, foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains/losses on the early retirement of debt, holding gains or losses on equity securities and pension settlement expense. In the first quarter of 2024, “Other” improved $119 million primarily due to the absence of a first-quarter 2023 consolidating tax adjustment as well as higher tax benefits related to stock compensation in the first quarter of 2024.

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Capital Resources and Liquidity			Table of Contents

Capital Resources and Liquidity

Financial Indicators

			Millions of Dollars
			March 31 2024			December 31 2023
Cash and cash equivalents			$	5,574		5,635
Short-term investments			487			971
Total debt			18,417			18,937
Total equity			49,325			49,279
Percent of total debt to capital*			27		%	28
Percent of floating-rate debt to total debt			2		%	2

*Capital includes total debt and total equity.

To meet our short-term and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs, and our ability to sell securities using our shelf registration statement. During the first three months of 2024, the primary uses of our available cash were $2.9 billion to support our ongoing capital expenditures and investments program, $1.3 billion to repurchase common stock, $0.9 billion to pay the ordinary dividend and VROC, and $0.5 billion to retire debt at maturity.

At March 31, 2024, we had total liquidity of $11.6 billion, comprised of cash and cash equivalents of $5.6 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion. In addition, we have $1.1 billion of long-term investments in debt securities. We believe current cash balances and cash generated by operating activities, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, acquisitions, dividend payments and debt obligations.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities was $5.0 billion for the first three months of 2024, compared with $5.4 billion for the corresponding period of 2023. The decrease is primarily due to lower realized natural gas prices, partially offset by higher bitumen prices and higher production volumes.

Our short-term and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of production volumes, as well as product and location mix, impacts our cash flows. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; impacts of a global pandemic; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage for these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. See the “Capital Expenditures and Investments” section.

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Investing Activities

For the first three months of 2024, we invested $2.9 billion in capital expenditures and investments. Our 2024 operating plan capital expenditures are currently expected to be between $11.0 billion to $11.5 billion. Our 2023 capital expenditures and investments were $11.2 billion. See the “Capital Expenditures and Investments” section.

In the first three months of 2024, we invested $0.3 billion in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4), and QatarEnergy LNG NFS(3) (NFS3).

We invest in short-term and long-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns. These investments include time deposits, commercial paper and debt securities classified as available for sale. 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 less than one year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities greater than one year.

Investing activities in the first three months of 2024 included net sales of $405 million of investments. We had net sales of $555 million of short-term investments and net purchases of $150 million of long-term investments*.* See Note 13.

Financing Activities

We have a revolving credit facility totaling $5.5 billion with an expiration date of February 2027. The credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at March 31, 2024.

Our debt balance at March 31, 2024 was $18.4 billion compared with $18.9 billion at December 31, 2023. The current portion of debt, including future payments for finance leases, is $1.1 billion at March 31, 2024. In March 2024, the company retired $461 million principal amount of our 2.125% Notes at maturity. Debt payments are expected to be made using current cash balances and cash provided by operating activities.

In March 2024, Moody's affirmed our long-term credit rating included below. 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 5 for additional information on debt and the revolving credit facility.

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2024, and December 31, 2023, we had direct bank letters of credit of $369 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Shelf Registration

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

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Capital Resources and Liquidity			Table of Contents

Capital Requirements

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

We believe in delivering value to our shareholders through our current three-tier return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend, a discretionary VROC payment, and through-cycle share repurchases. 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 expected 2024 total return of capital is at least $9 billion.

In the first three months of 2024, we paid ordinary dividends of $0.58 per share and VROC payments of $0.20 per share. In the first three months of 2023, we paid ordinary dividends of $0.51 per share and VROC payments of $0.70 per share.

In May 2024, we declared an ordinary dividend of $0.58 per share and a VROC payment of $0.20 per share, payable June 3, 2024, to shareholders of record on May 13, 2024.

In late 2016, we initiated our current share repurchase program. As of October 2022, we had announced a total authorization to repurchase up to $45 billion of our common stock. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. As of March 31, 2024, share repurchases since the inception of our current program totaled 395.0 million shares and $30.1 billion. In the three months ended March 31, 2024, we repurchased 11.6 million shares for a cost of $1.3 billion.

See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2023 Annual Report on Form 10-K.

Capital Expenditures and Investments

			Millions of Dollars
			Three Months Ended March 31
			2024			2023
Alaska			$	720		406
Lower 48			1,616			1,704
Canada			152			136
Europe, Middle East and North Africa			219			209
Asia Pacific			45			63
Corporate and Other			164			379
Capital expenditures and investments			$	2,916		2,897

During the first three months of 2024, capital expenditures and investments supported key operating activities and acquisitions, primarily:

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

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

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

• Development activities across assets in Norway.

• Continued development activities in Malaysia and China.

• Investments in PALNG, NFE4, and NFS3.

Our 2024 operating plan capital expenditure guidance is currently expected to be $11.0 billion to $11.5 billion. Our operating plan capital was $11.2 billion in 2023.

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Guarantor Summarized Financial Information

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

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

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

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

• Non-Obligated Subsidiaries are excluded from the presentation.

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

Summarized Income Statement Data

			Millions of Dollars
			Three Months Ended March 31, 2024
Revenues and Other Income			$	9,190
Income (loss) before income taxes*			2,462
Net Income (Loss)			2,551

*Includes approximately $1.9 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

			Millions of Dollars
			March 31, 2024			December 31, 2023
Current assets			$	6,236		8,008
Amounts due from Non-Obligated Subsidiaries, current			1,443			1,565
Noncurrent assets			94,794			91,155
Amounts due from Non-Obligated Subsidiaries, noncurrent			9,550			8,936
Current liabilities			7,938			7,337
Amounts due to Non-Obligated Subsidiaries, current			4,643			3,990
Noncurrent liabilities			50,232			49,105
Amounts due to Non-Obligated Subsidiaries, noncurrent			32,859			31,241

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Contingencies

We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 9.

Legal and Tax Matters

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

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

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 56–58 of our 2023 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under the CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of March 31, 2024, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

For remediation activities in the U.S. and Canada, our consolidated balance sheet included a total environmental accrual of $184 million at both March 31, 2024 and December 31, 2023. We expect to incur a substantial amount of these expenditures within the next 30 years.

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

See Part I—Item 1A—Risk Factors – "We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations," in our 2023 Annual Report on Form 10-K and Note 9 for information on environmental litigation.

Climate Change

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws and regulations focusing on GHG or methane emissions reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. For examples of legislation and precursors for possible regulation that do or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58–59 of our 2023 Annual Report on Form 10-K.

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Company Response to Climate-Related Risks

In 2020, we adopted a Paris-aligned climate-related risk framework with an ambition to reduce our operational (Scope 1 and 2) emissions to net-zero by 2050. The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, technologies for emissions reduction, alternative energy technologies and changes in consumer trends. The strategy sets out our choices around portfolio composition, emissions reductions, targets and incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.

An important component of our Climate Risk Strategy is the Plan for the Net-Zero Energy Transition (the 'Plan'). The Plan outlines how we intend to play a valued role in the energy transition by executing on our Triple Mandate to: reliably and responsibly meet energy transition pathway demand, deliver competitive returns on and of capital and focus on achieving our net-zero operational emissions ambition. The Plan also outlines how we intend to apply our strategic capabilities and resources to meet the challenges posed by climate change in an economically viable, accountable and actionable way that balances the interests of our stakeholders.

Key elements of the Plan include:

• Maintaining strategic flexibility

◦Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet transition pathway energy demand.

◦Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.

• Reducing Scope 1 and 2 emissions

◦Setting targets for emissions over which we have ownership and control, with an ambition to become a net-zero company for Scope 1 and 2 emissions by 2050.

• Addressing Scope 3 emissions

◦Advocating for a well-designed, economy-wide price on carbon and engaging in development of other policy and legislation to address end-use emissions.

◦Working with our suppliers for alignment on GHG emissions reductions.

• Contributing to an orderly transition

◦Building an attractive LNG portfolio.

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

Our Plan does not include a Scope 3 (end-use) emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand and with the shape and pace of technology and policy yet to be determined, setting and meeting Scope 3 targets would require a shift of production to other global operators that have established less ambitious targets or no targets to reduce their own operational emissions or do not have any other ambitions or plans to manage climate-related risks, potentially eroding energy security and affordability as well as undercutting global climate change objectives. This is why we have consistently taken a prominent role in advocating for a well-designed, economy wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include regulatory action, such as support for the direct regulation of methane.

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

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

• Accelerated our GHG intensity reduction target to 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.

• Achieved the Gold Standard Pathway in the Oil and Gas Methane Partnership 2.0 Initiative.

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

Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technology organization. See Part I—Item 1A—Risk Factors – "Existing and future laws, regulations and internal initiatives relating to global climate changes, such as limitations on GHG emissions, may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products," and "Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation," in our 2023 Annual Report on Form 10-K and Note 9 for information on climate change litigation.

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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 “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “intend,” “goal,” “guidance,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, NGLs and carbon pricing, including the imposition of price caps; regulation or taxation; and other political, economic or diplomatic developments, including as a result of any ongoing military conflict, including the conflicts in Ukraine and the Middle East.

• Volatility in the commodity futures markets.

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

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

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

• Our inability to execute, or delays in the completion of, 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 our 2023 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

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