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

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition," “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 50**.

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

Business Environment and Executive Overview

ConocoPhillips is one of the world’s leading E&P companies based on production and reserves, with operations and activities in 13 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at September 30, 2024, we employed approximately 10,300 people worldwide and had total assets of $97 billion.

Pending Acquisition of Marathon Oil Corporation

In May 2024, we announced a definitive agreement (the Merger Agreement) to acquire Marathon Oil Corporation (Marathon Oil) in an all-stock transaction (the Marathon Oil acquisition), inclusive of Marathon Oil's debt of approximately $5.3 billion at June 30, 2024. Under the terms of the Merger Agreement, which has been unanimously approved by the boards of directors of each company, Marathon Oil stockholders will receive 0.255 shares of ConocoPhillips common stock for each Marathon Oil share. We expect that the Marathon Oil acquisition will add high-quality, low cost of supply, development opportunities to our existing U.S. onshore portfolio and additional LNG capacity to our global LNG portfolio. On August 29, 2024, Marathon Oil announced that its stockholders had approved the transaction. We anticipate closing late in the fourth quarter of 2024, subject to regulatory clearances and other customary closing conditions. See Item 1A. Risk Factors.

In May 2024, as part of our Marathon Oil acquisition announcement, we stated that we expected at least $500 million in synergies, within the first full year following the close of the transaction. We now expect to reflect synergies that significantly exceed our initial $500 million guidance. Concurrent with our Marathon Oil acquisition announcement, we detailed a plan to repurchase over $7 billion of shares in the first full year following the closing of the transaction and over $20 billion of shares in total over the first three years, based on commodity prices at the time of the announcement. Through this plan we expect to retire the equivalent amount of newly issued equity from the transaction in two to three years. Further, in conjunction with the Marathon Oil acquisition announcement, we announced a plan to dispose of approximately $2 billion of assets across the portfolio pursuant to ongoing high-grading and optimization efforts.

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Management’s Discussion and Analysis			Table of Contents

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 progressing toward our net-zero operational emissions ambition. We call this our Triple Mandate, and it represents our commitment to create long-term value for our stakeholders.

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

In the third quarter, we announced further growth to our global LNG portfolio. In July, we entered into an 18-year agreement securing regasification capacity at the Zeebrugge LNG terminal in Belgium which includes regasification services for approximately 0.75 MTPA of LNG beginning in 2027. In July, we also entered into a long-term LNG sales agreement for approximately 0.5 MTPA into Asia starting in 2027. These agreements provide additional access to both the European and Asian natural gas markets.

We continue to optimize our portfolio geared towards our returns-focused value proposition. In October, we signed an agreement to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit in Alaska. This transaction is expected to close in the fourth quarter of 2024. See Note 3.

In October, we declared a fourth-quarter ordinary dividend of $0.78 per share, representing an increase of 34 percent which incorporates the prior VROC equivalent of $0.20 per share. We also reconfirmed our 2024 planned return of capital to shareholders of at least $9 billion. Additionally in October, our Board of Directors approved an increase to our existing share repurchase program authorization by the lesser of $20 billion or the number of shares issued in the Marathon Oil transaction.

Production was 1,917 MBOED in the third quarter of 2024, an increase of 111 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2024 production increased by 47 MBOED or three percent from the same period a year ago.

Third-quarter 2024 production resulted in $5.8 billion of cash provided by operating activities. We returned $1.2 billion to shareholders through share repurchases and $0.9 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents, restricted cash and short-term investments totaling $7.1 billion and long-term investments in debt securities of $1.0 billion.

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

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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 $80.18 per barrel in the third quarter of 2024, a decrease of eight percent compared with $86.76 per barrel in the third quarter of 2023. WTI at Cushing crude oil prices averaged $75.10 per barrel in the third quarter of 2024, a decrease of nine percent compared with $82.26 per barrel in the third quarter of 2023. Oil prices were lower in the third quarter of 2024 due to slower global demand growth relative to the third quarter of 2023 and higher supplies from non-OPEC Plus countries.

Henry Hub natural gas prices averaged $2.15 per MMBTU in the third quarter of 2024, a decrease of 15 percent compared with $2.54 per MMBTU in the third quarter of 2023. Henry Hub prices decreased due to excess North American natural gas storage levels following a mild 2023-2024 winter. Lower 48 segment realized natural gas prices decreased to $0.18 per MCF in the third quarter of 2024 driven by lower regional prices related to pipeline capacity constraints.

Our realized bitumen price averaged $47.32 per barrel in the third quarter of 2024, a decrease of 18 percent compared with $57.85 per barrel in the third quarter of 2023. The decrease in the third quarter of 2024 was driven by widening WCS differentials in Canada, lower heavy oil refinery demand on the U.S. Gulf Coast and impacts associated with lower sales volumes from Surmont due to a planned turnaround at one of our central processing facilities.

For the third quarter of 2024, our total average realized price was $54.18 per BOE compared with $60.05 per BOE in the third quarter of 2023.

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Key Operating and Financial Summary

• Reported third-quarter 2024 earnings per share of $1.76;

• Generated cash provided by operating activities of $5.8 billion;

• Raised ordinary dividend by 34 percent to $0.78 per share and increased existing share repurchase authorization by up to $20 billion;

• Delivered total company production of 1,917 MBOED;

• Achieved record lower 48 production of 1,147 MBOED, including 781 MBOED from the Permian, 246 MBOED from the Eagle Ford and 107 MBOED from the Bakken;

• Successfully completed planned turnarounds, primarily in Canada and the Lower 48;

• Exercised preferential rights and signed an agreement to acquire additional working interests in the Kuparuk River and Prudhoe Bay units in Alaska for approximately $300 million, with expected close by year-end, subject to customary closing conditions;

• Distributed $2.1 billion to shareholders, including $1.2 billion through share repurchases and $0.9 billion through the ordinary dividend and VROC;

• Ended the quarter with cash, cash equivalents, restricted cash and short-term investments of $7.1 billion and long-term investments of $1.0 billion.

Outlook

Production, Capital and DD&A

Fourth-quarter 2024 production is expected to be 1.99 to 2.03 MMBOED. Full-year production is expected to be approximately 1.94 to 1.95 MMBOED, as compared to prior guidance of 1.93 to 1.94 MMBOED.

All other guidance items remain unchanged.

Guidance excludes any impact from previously announced transactions.

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Results of Operations			Table of Contents

Results of Operations

Unless otherwise indicated, discussion of consolidated results for the three- and nine-month periods ended September 30, 2024, is based on a comparison with the corresponding period of 2023.

Consolidated Results

Summary Operating Statistics

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Average Net Production
Crude oil (MBD)
Consolidated operations			945			914			938			919
Equity affiliates			12			13			14			13
Total crude oil			957			927			952			932
Natural gas liquids (MBD)
Consolidated operations			302			283			287			274
Equity affiliates			8			8			8			8
Total natural gas liquids			310			291			295			282
Bitumen (MBD)			87			64			116			66
Natural gas (MMCFD)
Consolidated operations			2,149			1,889			2,102			1,903
Equity affiliates			1,232			1,252			1,249			1,223
Total natural gas			3,381			3,141			3,351			3,126
Total Production (MBOED)			1,917			1,806			1,921			1,801
Total Production (MMBOE)			176			166			526			492

			Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations			$	76.78		83.22			78.90			78.34
Equity affiliates			76.11			78.73			77.72			78.19
Total crude oil			76.77			83.15			78.88			78.34
Natural gas liquids (per bbl)
Consolidated operations			21.16			22.52			22.07			22.45
Equity affiliates			49.91			39.53			50.64			46.25
Total natural gas liquids			21.93			23.01			22.88			23.12
Bitumen (per bbl)			47.32			57.85			48.89			42.03
Natural gas (per MCF)
Consolidated operations			1.99			3.29			2.25			3.94
Equity affiliates			8.41			7.73			8.19			8.60
Total natural gas			$	4.42		5.06			4.53			5.79

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Results of Operations			Table of Contents

			Millions of Dollars
			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Exploration Expenses
General administrative, geological and geophysical, lease rental and other			$	70		43			236			162
Leasehold impairment			—			12			4			42
Dry holes			—			37			44			109
			$	70		92			284			313

Total Company Production

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. In the quarter ended September 30, 2024, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.

Total production in the third quarter of 2024 was 1,917 MBOED, an increase of 111 MBOED or six percent from the same period a year ago. Total production in the nine-month period of 2024 was 1,921 MBOED, an increase of 120 MBOED or seven percent from the same period a year ago. Production increases include:

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

• Our Surmont acquisition, which closed in October 2023. See Note 3.

Production increases were partially offset by:

• Normal field decline.

• Planned turnaround activity across our global operations.

After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2024 production increased by 47 MBOED or three percent from the same period a year ago. After adjusting for closed acquisitions and dispositions, production in the nine-month period of 2024 increased 55 MBOED or three percent from the same period a year ago.

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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.

Below is select financial data provided on a consolidated basis. The full Income Statement can be found in Item 1. Financial Statements.

			Millions of Dollars
			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Sales and other operating revenues			$	13,041		14,250			40,509			41,412
Gain (loss) on dispositions			(2)			108			86			200
Purchased commodities			4,747			5,543			14,939			16,297
Production and operating expenses			2,261			1,995			6,440			5,660
Depreciation, depletion and amortization			2,390			2,095			6,935			6,047
Taxes other than income taxes			476			536			1,567			1,624

Sales and other operating revenues decreased $1,209 million in the third quarter of 2024 and decreased $903 million in the nine-month period of 2024, respectively. Decreases in the third quarter were due to lower realized prices of $865 million, partially offset by higher volumes of $404 million. Decreases in the nine-month period of 2024 were due to lower realized natural gas prices of $642 million, partially offset by higher volumes of $1,368 million. Additional decreases to revenues in both the three- and nine-month periods of 2024 resulted from the timing of sales as compared with the corresponding periods of 2023.

Gain (loss) on dispositions decreased $110 million in the third quarter of 2024 and $114 million in the nine-month period of 2024 primarily due to the absence of the divestiture of an equity investment in our Lower 48 segment.

Purchased commodities for the three- and nine-month periods of 2024 decreased $796 million and $1,358 million, respectively. The third quarter of 2024 decrease was driven by lower gas and crude prices, partially offset by higher crude volumes. The nine-month period of 2024 decrease was driven by lower gas prices, partially offset by higher crude volumes.

Production and operating expenses for the three- and nine-month periods of 2024 increased $266 million and $780 million, respectively, due to higher lease operating expenses, transportation related costs and well work activities in our Lower 48 and Alaska segments, higher volumes primarily in our Canada and Lower 48 segments as well as higher expenses associated with the Surmont turnaround in our Canada segment.

DD&A expenses for the three- and nine-month periods of 2024 increased $295 million and $888 million, respectively, mainly due to higher rates in our Lower 48 and Alaska segments and higher volumes primarily in our Canada and Lower 48 segments.

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Segment Results

Unless otherwise indicated, discussion of segment results for the three- and nine-month periods ended September 30, 2024, is based on a comparison with the corresponding period of 2023 and are shown after-tax.

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

			Millions of Dollars
			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Alaska			$	267		448			973			1,236
Lower 48			1,241			1,781			3,881			4,863
Canada			25			186			466			224
Europe, Middle East and North Africa			298			253			853			882
Asia Pacific			455			465			1,411			1,374
Other International			1			(2)			3			(5)
Corporate and Other			(228)			(333)			(648)			(624)
Net income (loss)			$	2,059		2,798			6,939			7,950

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

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Results of Operations			Table of Contents

Alaska

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues			$	1,481		1,801			4,934			5,245
Production and operating expenses			520			475			1,489			1,375
Depreciation, depletion and amortization			309			259			954			786
Taxes other than income taxes			98			151			362			426
Net Income (Loss) ($MM)			$	267		448			973			1,236
Average Net Production
Crude oil (MBD)			162			165			171			173
Natural gas liquids (MBD)			14			14			14			16
Natural gas (MMCFD)			37			36			38			38
Total Production (MBOED)			182			185			191			195
Total Production (MMBOE)			17			17			52			53
Average Sales Prices
Crude oil ($ per bbl)			$	81.32		86.98			83.89			81.66
Natural gas ($ per MCF)			3.98			4.40			3.97			4.47

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2024, Alaska contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Alaska reported earnings of $267 million and $973 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $448 million and $1,236 million in the three- and nine-month periods of 2023, respectively.

Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $68 million, lower volumes of $16 million. Decreases to earnings in the third quarter of 2024 included higher DD&A expenses of $36 million due to higher rates as a result of prior year-end downward reserve revisions and higher production and operating expenses of $33 million driven by higher lease operating expenses and well work activity. The decreases to earnings were partially offset by lower taxes other than income taxes of $38 million due to lower taxes driven by increased capital expenditures.

Earnings in the nine-month period of 2024 included lower revenues resulting from lower volumes of $55 million, partially offset by higher realized prices of $80 million. Decreases to earnings in the nine-month period of 2024 included higher DD&A expenses of $123 million due to higher rates as a result of year-end downward reserve revisions, higher production and operating expenses of $83 million driven by higher well work activity and lease operating expenses. The decreases to earnings were partially offset by lower taxes other than income taxes of $47 million due to lower taxes driven by increased capital expenditures.

Production

Average production decreased 3 MBOED and 4 MBOED in the three- and nine-month periods of 2024, respectively. Decreases to production were primarily due to normal field decline, partially offset by new wells online.

Planned Acquisition

In October, we signed an agreement to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit. This transaction is expected to close in the fourth quarter of 2024. See Note 3.

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Lower 48

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues			$	9,080		9,883			27,441			28,316
Production and operating expenses			1,180			1,129			3,420			3,118
Depreciation, depletion and amortization			1,640			1,489			4,629			4,215
Taxes other than income taxes			324			326			1,014			1,028
Net Income (Loss) ($MM)			$	1,241		1,781			3,881			4,863
Average Net Production
Crude oil (MBD)			603			572			577			566
Natural gas liquids (MBD)			278			263			263			251
Natural gas (MMCFD)			1,596			1,490			1,557			1,462
Total Production (MBOED)			1,147			1,083			1,099			1,061
Total Production (MMBOE)			106			100			301			290
Average Sales Prices
Crude oil ($ per bbl)			$	74.73		80.75			76.29			75.77
Natural gas liquids ($ per bbl)			20.64			22.03			21.58			22.02
Natural gas ($ per MCF)			0.18			2.24			0.67			2.19

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, producing properties in the Gulf of Mexico and commercial operations. As of September 30, 2024, the Lower 48 contributed 63 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

Net Income (Loss)

Lower 48 reported earnings of $1,241 million and $3,881 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $1,781 million and $4,863 million in the three- and nine-month periods of 2023, respectively.

Earnings in the third quarter of 2024 included lower revenues resulting from lower overall realized prices of $494 million, partially offset by higher volumes of $190 million. Decreases to earnings in the third quarter of 2024 included higher DD&A expenses of $118 million, driven by higher volumes of $64 million and higher rates of $52 million, the absence of a gain from the divestiture of an equity investment of $100 million and higher production and operating expenses of $40 million driven by increased transportation related costs of $30 million.

Earnings in the nine-month period of 2024 included lower revenues resulting from lower overall realized prices of $433 million, partially offset by higher volumes of $287 million. Decreases to earnings in the nine-month period of 2024 included higher DD&A expenses of $323 million, driven by higher volumes of $166 million and higher rates of $160 million, higher production and operating expenses of $235 million, driven by increased transportation related costs of $93 million and increased lease operating expenses of $74 million, and the absence of a gain from the divestiture of an equity investment of $100 million.

Production

Average production increased 64 MBOED and 38 MBOED in the three- and nine-month periods of 2024, respectively. Increases to production were primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.

Production increases were partly offset by normal field decline.

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Results of Operations			Table of Contents

Canada

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues			$	660		808			2,537			2,100
Production and operating expenses			269			140			709			403
Depreciation, depletion and amortization			147			89			471			264
Taxes other than income taxes			6			5			25			17
Net Income (Loss) ($MM)			$	25		186			466			224
Average Net Production
Crude oil (MBD)			15			8			17			7
Natural gas liquids (MBD)			7			3			6			3
Bitumen (MBD)			87			64			116			66
Natural gas (MMCFD)			121			57			114			60
Total Production (MBOED)			129			85			158			86
Total Production (MMBOE)			12			8			43			23
Average Sales Prices
Crude oil ($ per bbl)			$	61.99		70.83			65.09			66.10
Natural gas liquids ($ per bbl)			28.11			26.26			30.13			24.09
Bitumen ($ per bbl)			47.32			57.85			48.89			42.03
Natural gas ($ per MCF)*			0.10			0.67			0.46			2.05

*Average sales prices include unutilized transportation costs.

The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations. As of September 30, 2024, Canada contributed 10 percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Canada reported earnings of $25 million and $466 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $186 million and $224 million in the three- and nine-month periods of 2023, respectively.

Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $49 million, partially offset by higher volumes of $104 million driven by our increased working interest in Surmont. Additional decreases to revenues resulted from the timing of sales as compared with the corresponding period of 2023. Decreases to earnings in the third quarter of 2024 included the absence of a $92 million third-quarter 2023 tax benefit recognized upon the closing of a Canada Revenue Agency audit, higher production and operating expenses of $89 million, driven by $61 million related to our increased working interest in Surmont and $50 million in expenses associated with a third quarter planned turnaround at Surmont, and higher DD&A expenses of $40 million.

Earnings in the nine-month period of 2024 included higher revenues resulting from higher volumes of $666 million, driven by our increased working interest in Surmont, and higher realized prices of $76 million. Decreases to earnings in the nine-month period of 2024 included higher production and operating expenses of $231 million, driven by $160 million related to our increased working interest in Surmont and $61 million in expenses associated with a third quarter planned turnaround at Surmont, higher DD&A expenses of $156 million, driven by higher volumes, and the absence of a $92 million third-quarter 2023 tax benefit recognized upon the closing of a Canada Revenue Agency audit.

Production

Average production increased 44 MBOED and 72 MBOED in the three- and nine-month periods of 2024, respectively. Increases to production resulted from our increased working interest in Surmont as well as new wells online in the Montney and Surmont. See Note 3.

Production increases were partly offset by planned turnaround activity at a Surmont central processing facility and normal field decline.

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Europe, Middle East and North Africa

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues			$	1,337		1,211			4,090			4,282
Production and operating expenses			154			139			471			430
Depreciation, depletion and amortization			189			134			544			426
Taxes other than income taxes			10			10			31			29
Net Income (Loss) ($MM)			$	298		253			853			882
Consolidated Operations
Average Net Production
Crude oil (MBD)			110			108			115			113
Natural gas liquids (MBD)			3			3			4			4
Natural gas (MMCFD)			351			264			346			297
Total Production (MBOED)			171			155			177			166
Total Production (MMBOE)			16			14			48			45
Average Sales Prices
Crude oil ($ per bbl)			$	80.88		87.45			83.45			83.37
Natural gas liquids ($ per bbl)			46.08			43.08			44.81			41.49
Natural gas ($ per MCF)			10.76			9.61			9.71			12.90

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

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea and the Norwegian Sea, Qatar, Libya and commercial and terminalling operations in the U.K. As of September 30, 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

Net Income (Loss)

Europe, Middle East and North Africa reported earnings of $298 million and $853 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $253 million and $882 million in the three- and nine-month periods of 2023, respectively.

Earnings in the third quarter of 2024 included higher revenues resulting from higher volumes of $31 million, partially offset by lower realized prices of $11 million primarily impacted by lower crude prices.

Earnings in the nine-month period of 2024 included lower revenues resulting from lower realized prices of $72 million primarily impacted by lower natural gas prices, partially offset by higher volumes of $54 million. Decreases to earnings included lower foreign exchange gains of approximately $37 million and higher DD&A expenses of $34 million.

Consolidated Production

Average consolidated production increased 16 MBOED and 11 MBOED in the three- and nine-month periods of 2024, respectively. Increases to production were primarily due to new wells online and improved performance in both Norway and Libya.

Production increases were partly offset by normal field decline and curtailed production in Libya due to the force majeure at Es Sider terminal. Force majeure was lifted in early October.

Exploration Activity

In the nine-month period of 2024, we charged approximately $40 million before-tax as dry hole expenses primarily for two partner operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea and the Busta suspended discovery well on license PL782S that was drilled in 2019.

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Asia Pacific

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Select financial data by segment before-tax ($MM)
Sales and other operating revenues			$	478		544			1,495			1,440
Production and operating expenses			110			101			281			280
Depreciation, depletion and amortization			97			117			314			338
Taxes other than income taxes			25			37			90			88
Net Income (Loss) ($MM)			$	455		465			1,411			1,374
Consolidated Operations
Average Net Production
Crude oil (MBD)			55			61			58			60
Natural gas (MMCFD)			44			42			47			46
Total Production (MBOED)			62			68			66			68
Total Production (MMBOE)			6			6			18			19
Average Sales Prices
Crude oil ($ per bbl)			$	80.84		89.10			84.15			83.95
Natural gas ($ per MCF)			3.62			3.77			3.75			4.08

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

The Asia Pacific segment has operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. As of September 30, 2024, Asia Pacific contributed four percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income (Loss)

Asia Pacific reported earnings of $455 million and $1,411 million in the three- and nine-month periods of 2024, respectively, compared with earnings of $465 million and $1,374 million in the three- and nine-month periods of 2023, respectively.

Earnings in the third quarter of 2024 included lower revenues resulting from lower realized prices of $41 million and lower volumes of $38 million. Decreases to earnings included the absence of a $52 million tax benefit associated with a deepwater tax incentive. The decreases to earnings were partially offset by higher earnings from equity affiliates of $38 million and foreign exchange gains of $30 million. See Note 19.

Earnings in the nine-month period of 2024 included a $76 million tax benefit associated with deepwater investment tax incentive, higher foreign exchange gains of approximately $38 million and lower DD&A expenses of $21 million. The increases to earnings were partially offset by the absence of a $52 million third quarter 2023 tax benefit associated with a deepwater investment tax incentive and lower earnings from equity affiliates of $50 million. See Note 19.

Consolidated Production

Average consolidated production decreased 6 MBOED and 2 MBOED in the three- and nine-month periods of 2024, respectively. Decreases to production were primarily due to normal field decline.

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

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Other International

			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Net Income (Loss) ($MM)			$	1		(2)			3			(5)

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

Corporate and Other

			Millions of Dollars
			Three Months Ended September 30						Nine Months Ended September 30
			2024			2023			2024			2023
Net Income (Loss)
Net interest expense			$	(79)		(91)			(261)			(267)
Corporate general and administrative expenses			(99)			(87)			(282)			(273)
Technology			(32)			(14)			(100)			(19)
Other income (expense)			(18)			(141)			(5)			(65)
			$	(228)		(333)			(648)			(624)

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

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

Technology includes our investments in low-carbon and other new technologies or businesses and licensing revenues. Other new technologies or businesses and licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery, as well as LNG. Earnings in Technology for the nine-month period of 2024 decreased due to increased costs in low-carbon and other new technologies and lower licensing revenues.

Other income (expense) or “Other” includes certain consolidating tax-related items, foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains/losses on the early retirement of debt, holding gains or losses on equity securities and pension settlement expense. “Other” increased in third quarter of 2024 primarily due to the absence of a 2023 consolidating tax adjustment and absence of 2023 foreign currency exchange losses.

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Capital Resources and Liquidity

Financial Indicators

			Millions of Dollars
			September 30 2024			December 31 2023
Cash and cash equivalents			$	5,221		5,635
Short-term investments			1,571			971
Total debt			18,304			18,937
Total equity			49,881			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 nine months of 2024, the primary uses of our available cash were $8.8 billion to support our ongoing capital expenditures and investments program, $3.5 billion to repurchase common stock, $2.7 billion to pay the ordinary dividend and VROC, $0.6 billion to retire debt at maturity and $0.6 billion net purchases of investments.

At September 30, 2024, we had total liquidity of $12.3 billion, comprised of cash and cash equivalents of $5.2 billion, short-term investments of $1.6 billion and available borrowing capacity under our credit facility of $5.5 billion. In addition, we have $1.0 billion of long-term investments in debt securities. We believe current cash balances and cash generated by operating activities, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, acquisitions, dividend payments and debt obligations.

Significant Changes in Capital

Operating Activities

Cash provided by operating activities was $15.7 billion for the first nine months of 2024, compared with $14.7 billion for the corresponding period of 2023. The increase is primarily due to changes in operational working capital, driven by lower Norway tax payments and deferral of certain 2024 U.S. income tax payments, alongside higher production, primarily from the Lower 48 and the Surmont 50 percent working interest acquired in the fourth quarter of 2023, partly offset by lower commodity prices and lower distributions from equity affiliates.

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

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

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

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Investing Activities

For the first nine months of 2024, we invested $8.8 billion in capital expenditures and investments. Our 2024 operating plan capital expenditures are currently expected to be approximately $11.5 billion. Our 2023 capital expenditures and investments were $11.2 billion. See the “Capital Expenditures and Investments” section.

In the third quarter of 2024, we signed a purchase and sale agreement for approximately $300 million, subject to customary adjustments, to acquire additional working interests in both the Kuparuk River Unit and the Prudhoe Bay Unit in Alaska. This transaction is expected to close in the fourth quarter of 2024. See Note 3.

In the first nine months of 2024, we invested $0.7 billion in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4) and QatarEnergy LNG NFS(3) (NFS3).

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

Investing activities in the first nine months of 2024 included net purchases of $599 million of investments. We had net purchases of $205 million of short-term investments and net purchases of $394 million of long-term investments*.* See Note 13.

Financing Activities

We have a revolving credit facility totaling $5.5 billion with an expiration date of February 2027. The credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million or as support for our commercial paper program. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at September 30, 2024.

Our debt balance at September 30, 2024 was $18.3 billion compared with $18.9 billion at December 31, 2023. The current portion of debt, including future payments for finance leases, is $1.3 billion at September 30, 2024. In the first quarter of 2024, the company retired $461 million principal amount of our 2.125% Notes at maturity. Debt payments are expected to be made using current cash balances and cash provided by operating activities.

The current long-term debt credit ratings are:

• Fitch: “A” with a “stable” outlook

• S&P: “A-” with a “stable” outlook

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

See Note 5 for additional information on debt and the revolving credit facility.

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At September 30, 2024, and December 31, 2023, we had direct bank letters of credit of $236 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Shelf Registration

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

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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 return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and through-cycle share repurchases. In connection with the pending transaction with Marathon Oil, share repurchases were restricted for a period of time pursuant to SEC regulations. These restrictions ended after the Marathon Oil stockholder approval on August 29, 2024 and share repurchases were subsequently resumed. We anticipate achieving at least $9 billion return of capital in 2024. See Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

In the first nine months of 2024, we paid ordinary dividends of $1.74 per share and VROC payments of $0.60 per share. In the first nine months of 2023, we paid ordinary dividends of $1.53 per share and VROC payments of $1.90 per share.

In October 2024, we declared an increase to our quarterly ordinary dividend from $0.58 per share to $0.78 per share, representing a 34 percent increase, effectively rolling the amount of the prior quarter VROC into the ordinary dividend. VROC remains a discretionary option in elevated price environments. The dividend is payable December 2, 2024, to shareholders of record on November 11, 2024.

In late 2016, we initiated our current share repurchase program. In October 2024, our Board of Directors approved an increase to our existing authorization of $45 billion by a total of the lesser of $20 billion or the number of shares issued in the Marathon Oil transaction, such that the Company is not to exceed $65 billion in aggregate purchases. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. As of September 30, 2024, share repurchases since the inception of our current program totaled 414.2 million shares and $32.3 billion. In the nine months ended September 30, 2024, we repurchased 30.8 million shares for a cost of $3.5 billion.

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

Capital Expenditures and Investments

			Millions of Dollars
			Nine Months Ended September 30
			2024			2023
Alaska			$	2,102		1,140
Lower 48			4,918			4,878
Canada			419			345
Europe, Middle East and North Africa			694			834
Asia Pacific			235			245
Corporate and Other			433			923
Capital expenditures and investments			$	8,801		8,365

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

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

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

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

• Development activities across assets in Norway.

• Continued development activities in Malaysia and China.

• Investments in PALNG, NFE4 and NFS3.

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

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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
			Nine Months Ended September 30, 2024
Revenues and Other Income			$	26,849
Income (loss) before income taxes*			6,779
Net Income (Loss)			6,939

*Includes approximately $6.3 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

			Millions of Dollars
			September 30 2024			December 31 2023
Current Assets			$	6,442		8,008
Amounts due from Non-Obligated Subsidiaries, current			1,491			1,565
Noncurrent Assets			102,119			91,155
Amounts due from Non-Obligated Subsidiaries, noncurrent			10,956			8,936
Current Liabilities			10,415			7,337
Amounts due to Non-Obligated Subsidiaries, current			6,282			3,990
Noncurrent Liabilities			54,731			49,105
Amounts due to Non-Obligated Subsidiaries, noncurrent			37,624			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 8.

Legal and Tax Matters

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

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

Environmental

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

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under the CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of September 30, 2024, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

For remediation activities in the U.S. and Canada, our consolidated balance sheet included a total environmental accrual of $209 million at September 30, 2024, compared with $184 million at December 31, 2023. We expect to incur a substantial amount of these expenditures within the next 30 years.

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

See Part I—Item 1A—Risk Factors – "We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations," in our 2023 Annual Report on Form 10-K and Note 8 for information on environmental litigation.

Climate Change

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

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Company Response to Climate-Related Risks

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

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

Key elements of the Plan include:

• Maintaining strategic flexibility

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

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

◦Track the energy transition through a comprehensive scenario planning process to calibrate and understand alternative energy transition pathways and test the resilience of our corporate strategy to climate risk.

• Reducing Scope 1 and 2 emissions

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

• Addressing Scope 3 (end-use) emissions

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

◦Working with our suppliers and commercial partners to reduce emissions along the value chain.

• Contributing to an orderly transition

◦Building an attractive LNG portfolio as an important component of responsibly meeting energy transition demand due to its lower GHG emissions than coal used for electricity generation.

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

Our Plan does not include a Scope 3 (end-use) emissions target. We recognize that end-use emissions must be reduced to meet global climate objectives. However, it is our view that supply-side constraints through Scope 3 targets for North American and European upstream oil and gas producers would be counterproductive to climate goals. In the absence of policy measures that address global demand, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions. This is why we have consistently taken a prominent role in advocating for a well-designed, economy-wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use. We have also expanded policy advocacy beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct regulation of methane.

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

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

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

• Continued methane emissions reductions activities in support of our near-zero methane emissions intensity (1.5 kilogram carbon dioxide equivalent per BOE) and introduced data quality improvements.

• Remained on schedule to meet a target of zero routine flaring by the end of 2025, five years sooner than the World Bank Initiative's goal of 2030.

Our emissions reduction efforts and net-zero ambition are supported by our multi-disciplinary Low-Carbon Technology organization. See Part I—Item 1A—Risk Factors – "Existing and future laws, regulations and internal initiatives relating to global climate changes, such as limitations on GHG emissions, may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products," and "Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation," in our 2023 Annual Report on Form 10-K and Note 8 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, costs and plans, objectives of management for future operations, the anticipated benefits of the Marathon Oil acquisition, the anticipated impact of the proposed transaction on the combined company’s business and future financial and operating results, the expected amount and timing of synergies from the proposed transaction and the anticipated closing date for the proposed transaction are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often identify our forward-looking statements by the words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Volatility in the commodity futures markets.

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

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

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

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

• Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals, consents or authorizations for the Marathon Oil acquisition or for any other pending or future asset dispositions or acquisitions, or that such approvals, consents or authorizations for such disposition or acquisition may be subject to conditions neither we nor Marathon Oil anticipated or may require modification to the terms of the transactions or the operation of our remaining business.

• Our or Marathon Oil’s inability to receive other requisite approvals for the Marathon Oil acquisition or, to satisfy other closing conditions on a timely basis or at all or the failure of the Marathon Oil acquisition to close for any other reason or to close on anticipated terms, including the anticipated tax treatment.

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

• Our inability to realize anticipated cost savings and capital expenditure reductions, including our inability to achieve the expected benefits and synergies from the Marathon Oil acquisition in a timely manner, or at all.

• Our inability to successfully integrate Marathon Oil’s business and technologies, which may result in the combined company not operating as effectively and efficiently as expected.

• Unanticipated difficulties or expenditures relating to the Marathon Oil acquisition.

• Negative effects of the pendency or completion of the Marathon Oil acquisition on our or Marathon Oil’s business relationships and business operations generally.

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

• The operation and financing of our joint ventures.

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

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

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

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

• The factors generally described in Part I—Item 1A in our 2023 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.