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 “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 September 30, 2023, we employed approximately 9,800 people worldwide and had total assets of $94 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 full upside exposure 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 the conflicts in Ukraine and the Middle East, OPEC Plus crude supplies, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.

The macro-environment, including the energy transition, also continues to evolve. We believe ConocoPhillips will continue to play an essential role by executing on three objectives: reliably and 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 value proposition to deliver superior returns to stockholders through price cycles is guided by foundational principles and capital allocation priorities that support our Triple Mandate. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance.

In July, we executed an agreement to purchase the remaining 50 percent interest in Surmont, an asset in our Canada segment. In October, we completed this purchase for approximately $2.7 billion of cash after customary adjustments, funded from proceeds received via debt offerings in August. The transaction also includes a contingent payment arrangement of up to an additional $0.3 billion over a five-year term. Now, as the 100 percent owner and operator of Surmont, we will seek to optimize the asset while remaining on track to achieve our previously announced corporate emissions intensity objectives. See Note 3.

In the third quarter of 2023, we issued new long-term debt to fund our acquisition of the remaining 50 percent working interest in Surmont. In the second quarter of 2023, we initiated and completed a strategic debt refinancing. These transactions extend the weighted average maturity of our portfolio and the second quarter refinancing reduces near-term debt maturities. See Note 6.

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Management’s Discussion and Analysis			Table of Contents

In September, we announced further progress on our global LNG strategy by signing a 15-year throughput agreement, securing additional regasification capacity at the Gate LNG terminal in the Netherlands. The 15-year agreement is for approximately 1.5 MTPA beginning in 2031. The additional capacity secures access to important markets for our growing LNG portfolio. Additionally, earlier in 2023, we further expanded our global LNG portfolio through a 30 percent direct equity investment in Port Arthur Liquefaction Holdings, LLC (PALNG) and a 25 percent equity interest in QatarEnergy LNG NFS(3) (NFS3). We also signed a 20-year offtake agreement at the Saguaro LNG export facility on the west coast of Mexico for approximately 2.2 MTPA, subject to Mexico Pacific reaching FID and other certain conditions precedent. See Note 3.

In November, we reconfirmed our 2023 planned return of capital to shareholders of $11 billion through our three-tier return of capital framework, significantly exceeding our commitment to return greater than 30 percent of our anticipated cash provided by operating activities for the full year. Also in November, we declared an increase to our quarterly ordinary dividend from $0.51 per share to $0.58 per share, representing a 14 percent increase. Beginning in the first quarter of 2024, ConocoPhillips plans to pay its quarterly ordinary dividend and VROC concurrently, and will announce such payments in the same quarter they will be paid.

Operationally, we remain focused on safely executing the business. Production was 1,806 MBOED in the third quarter of 2023, an increase of 52 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2023 production increased by 49 MBOED or three percent from the same period a year ago. Organic growth from Lower 48 and other development programs more than offset normal field decline and downtime.

Third-quarter production resulted in $5.4 billion of cash provided by operating activities. We also returned $1.3 billion to shareholders through share repurchases and $1.3 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents and short-term investments totaling $9.4 billion.

Also in the third quarter of 2023, we re-invested $2.5 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 $86.76 per barrel in the third quarter of 2023, a decrease of 14 percent compared with $100.85 per barrel in the third quarter of 2022. WTI at Cushing crude oil prices averaged $82.26 per barrel in the third quarter of 2023, a decrease of 10 percent compared with $91.56 per barrel in the third quarter of 2022. Oil prices normalized relative to third quarter 2022 prices which reflected elevated geopolitical risks associated with Russian supplies and expectations for high winter oil consumption which did not fully materialize.

Henry Hub natural gas prices averaged $2.54 per MMBTU in the third quarter of 2023, a decrease of 69 percent compared with $8.20 per MMBTU in the third quarter of 2022. Henry Hub prices decreased due to excess North American natural gas storage levels following a mild 2022-2023 winter.

Our realized bitumen price averaged $57.85 per barrel in the third quarter of 2023, an increase of 16 percent compared with $49.77 per barrel in the third quarter of 2022. The increase in the third quarter of 2023 was driven by higher blend prices for Surmont sales, largely attributed to narrowing WCS differentials following OPEC Plus heavy oil supply cuts. We continue to optimize bitumen price realizations through diluent recovery unit operating improvements as well as blending and transportation strategies.

For the third quarter of 2023, our total average realized price was $60.05 per BOE compared with $83.07 per BOE in the third quarter of 2022.

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Management’s Discussion and Analysis			Table of Contents

Key Operating and Financial Summary

Significant items during the third quarter of 2023 and recent announcements included the following:

• Increased the quarterly ordinary dividend by 14 percent to $0.58 per share.

• Completed the purchase of the remaining 50 percent interest in Surmont in October for approximately $2.7 billion as well as future contingent payments of up to $0.4 billion CAD ($0.3 billion).

• Achieved first steam at Surmont Pad 267 and startup at the second phase of Montney's central processing facility in Canada.

• Reached first production ahead of schedule in October at Tommeliten A and partner-operated Breidablikk and Kobra East & Gekko in Norway and partner-operated Bohai Phase 4B in China.

• Further diversified LNG portfolio by signing a 15-year throughput agreement for approximately 1.5 MTPA of regasification at the Gate LNG terminal in the Netherlands.

• Delivered company and Lower 48 production of 1,806 MBOED and 1,083 MBOED, respectively.

• Generated cash provided by operating activities of $5.4 billion.

• Distributed $2.6 billion to shareholders through a three-tier framework, including $1.3 billion through the ordinary dividend and VROC and $1.3 billion through share repurchases.

• Ended the quarter with cash, cash equivalents, and restricted cash of $9.1 billion and short-term investments of $0.6 billion, which included proceeds from long-term debt issuances of $2.7 billion to fund the Surmont acquisition.

Outlook

Production, Capital and DD&A

All guidance has been updated to reflect the acquisition of an additional 50 percent interest in Surmont but excludes any impacts from the previously announced APLNG transaction.

Fourth-quarter 2023 production is expected to be 1.86 to 1.90 MMBOED. Full-year production guidance is expected to be approximately 1.82 MMBOED, as compared to prior guidance of 1.80 to 1.81 MMBOED, due to the Surmont acquisition.

Full-year guidance for DD&A was updated to $8.3 billion versus prior guidance of $8.2 billion, primarily due to the Surmont acquisition.

Full-year capital guidance remains unchanged.

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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, 2023, is based on a comparison with the corresponding period of 2022.

Consolidated Results

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
			2023			2022						2023			2022
Alaska			$	448		580						1,236			1,851
Lower 48			1,781			2,653						4,863			9,024
Canada			186			119						224			726
Europe, Middle East and North Africa			253			922						882			1,719
Asia Pacific			465			520						1,374			2,181
Other International			(2)			(28)						(5)			(28)
Corporate and Other			(333)			(239)						(624)			(42)
Net income			$	2,798		4,527						7,950			15,431

Net income in the third quarter of 2023 decreased $1,729 million. Third quarter earnings were negatively impacted by:

• Lower realized commodity prices.

• Higher DD&A expenses primarily in the Lower 48 segment due to higher rates resulting from reserve revisions driven by higher operating costs and lower prices as well as higher overall production volumes.

• Higher production and operating expenses primarily driven by increased well work activity and higher production volumes in the Lower 48 segment.

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

• Lower foreign exchange gains related to the USD strengthening against the NOK and losses associated with forward contracts to buy CAD, related to our planned acquisition of additional interest in Surmont. See Note 3 and Note 10.

Offsets to the earnings decreases include:

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

• Higher sales volumes driven primarily by development in the Lower 48 segment.

• Tax benefits of $92 million recognized upon the closing of a Canada Revenue Agency audit and $52 million associated with deepwater tax incentives for Malaysia Block J. See Note 20.

• Gains from dispositions primarily related to the divestment of an equity investment in the Lower 48 segment and the absence of a loss on the sale of certain noncore assets in the third quarter of 2022.

Net income in the nine-month period ended September 30, 2023, decreased $7,481 million. In addition to the items mentioned above, earnings in the nine-month period were negatively impacted by:

• Absence of a $515 million tax benefit related to the closing of an IRS audit in the first quarter of 2022.

See Note 20.

• Absence of gains from dispositions associated with the divestiture of our Indonesia assets, gains from dispositions related to the sale of certain noncore assets in the Lower 48 segment and contingent payments associated with previous asset sales.

• Absence of gains associated with our Cenovus Energy (CVE) common shares which were fully divested in the first quarter of 2022. See Note 5.

• Higher selling, general and administrative expenses primarily due to mark to market adjustments associated with certain compensation programs.

See the “Segment Results” section for additional information.

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Results of Operations			Table of Contents

Income Statement Analysis

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

Sales and other operating revenues for the three- and nine-month periods of 2023 decreased $6,763 million and $18,524 million, respectively, primarily due to lower realized commodity prices, partially offset by higher sales volumes driven primarily by development in the Lower 48 segment. Decreases in the nine-month period also include the impact of the divestiture of our Indonesia assets in the first quarter of 2022.

Equity in earnings of affiliates for the three- and nine-month periods of 2023 decreased $173 million and $212 million, respectively, due to lower earnings primarily driven by lower LNG and crude prices*.*

Gain (loss) on dispositions for the third quarter of 2023 increased $148 million primarily due to the divestiture of an equity investment in our Lower 48 segment as well as the absence of a loss on the sale of certain noncore assets in the Lower 48 segment in the third quarter of 2022. For the nine-month period of 2023, gain (loss) on dispositions decreased $839 million primarily due to the absence of a gain from the divestiture of our Indonesia assets in the first quarter of 2022, and the absence of contingent payments associated with previous dispositions in our Canada and Lower 48 segments, partially offset by the gains recognized in the third quarter of 2023.

Purchased commodities for the three- and nine-month periods of 2023 decreased $3,708 million and $8,939 million, respectively, primarily due to lower prices across all commodities as well as lower volumes in the three month period.

Production and operating expenses for the three- and nine-month periods of 2023 increased $196 million and $539 million, respectively, primarily due to increased well work activity and higher production volumes in the Lower 48 segment.

Selling, general and administrative expenses increased $102 million in the nine-month period of 2023 primarily due to mark to market adjustments associated with certain compensation programs.

DD&A expenses for the three- and nine-month periods of 2023 increased $223 million and $542 million, respectively, mainly due to higher rates from impacts to reserve revisions driven by higher operating costs and lower prices and higher overall production volumes primarily due to development in the Lower 48 segment.

Taxes other than income taxes for the three- and nine-month periods of 2023 decreased $307 million and $1,053 million, respectively, driven by lower commodity prices, partially offset by higher production volumes.

Foreign currency transaction (gain) loss for the three- and nine-month periods of 2023 was impaired by $148 million and $136 million, respectively, primarily as a result of lower gains related to the USD strengthening against the NOK and losses associated with forward contracts to buy CAD, related to our planned acquisition of additional interest in Surmont in the three month period. See Note 3 and Note 10.

See Note 20—Income Taxes for information regarding our Income tax provision and effective tax rate.

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Results of Operations			Table of Contents

Summary Operating Statistics

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Average Net Production
Crude oil (MBD)
Consolidated operations			914			882			919			881
Equity affiliates			13			13			13			13
Total crude oil			927			895			932			894
Natural gas liquids (MBD)
Consolidated operations			283			263			274			238
Equity affiliates			8			8			8			8
Total natural gas liquids			291			271			282			246
Bitumen (MBD)			64			69			66			65
Natural gas (MMCFD)
Consolidated operations			1,889			1,899			1,903			1,966
Equity affiliates			1,252			1,214			1,223			1,192
Total natural gas			3,141			3,113			3,126			3,158
Total Production (MBOED)			1,806			1,754			1,801			1,731

			Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations			$	83.22		97.60			78.34			101.19
Equity affiliates			78.73			94.58			78.19			101.38
Total crude oil			83.15			97.56			78.34			101.19
Natural gas liquids (per bbl)
Consolidated operations			22.52			34.83			22.45			39.06
Equity affiliates			39.53			55.51			46.25			64.91
Total natural gas liquids			23.01			35.47			23.12			39.90
Bitumen (per bbl)			57.85			49.77			42.03			63.14
Natural gas (per MCF)
Consolidated operations			3.29			14.14			3.94			10.98
Equity affiliates			7.73			11.37			8.60			10.15
Total natural gas			5.06			13.04			5.79			10.66

			Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental and other			$	43		57			162			165
Leasehold impairment			12			7			42			23
Dry holes			37			25			109			113
			$	92		89			313			301

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Results of Operations			Table of Contents

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. At September 30, 2023, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.

Total production in the third quarter of 2023 was 1,806 MBOED, an increase of 52 MBOED or three percent. Total production in the nine-month period of 2023 was 1,801 MBOED, an increase of 70 MBOED or four percent. Production increases were primarily due to new wells online in the Lower 48, Alaska, Australia, Canada, China and Malaysia.

Production increases were partially offset due to normal field decline.

After adjusting for impacts from closed acquisitions and dispositions, third-quarter 2023 production increased by 49 MBOED or three percent from the same period a year ago. Organic growth from Lower 48 and other development programs more than offset normal field decline and downtime.

After adjusting for impacts from closed acquisitions and dispositions, production in the nine-month period of 2023 increased 71 MBOED or four percent from the same period a year ago. Organic growth from Lower 48 and other development programs more than offset normal field decline and downtime.

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Segment Results

Unless otherwise indicated, discussion of segment results for the three- and nine-month periods ended September 30, 2023, is based on a comparison with the corresponding period of 2022 and are shown after-tax.

Alaska

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Income ($MM)			$	448		580			1,236			1,851
Average Net Production
Crude oil (MBD)			165			171			173			177
Natural gas liquids (MBD)			14			15			16			16
Natural gas (MMCFD)			36			29			38			33
Total Production (MBOED)			185			191			195			198
Average Sales Prices
Crude oil ($ per bbl)			$	86.98		103.90			81.66			104.83
Natural gas ($ per MCF)			4.40			4.38			4.47			3.82

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2023, Alaska contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income

Earnings from Alaska decreased $132 million and $615 million in the three- and nine-month periods of 2023, respectively. Decreases to earnings were primarily due to lower realized crude oil prices.

Offsets to the earnings decreases include lower taxes other than income taxes driven by lower realized crude oil prices.

In addition to the items mentioned above, in the nine-month period of 2023, earnings impacts include:

• Lower sales volumes.

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

Production

Average production decreased 6 MBOED and 3 MBOED in the three- and nine-month periods of 2023, respectively. Decreases to production were primarily due to normal field decline.

Offsets to the production decreases were new wells online at our Western North Slope and Greater Kuparuk Area assets.

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Results of Operations			Table of Contents

Lower 48

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Income ($MM)			$	1,781		2,653			4,863			9,024
Average Net Production
Crude oil (MBD)			572			537			566			534
Natural gas liquids (MBD)			263			241			251			216
Natural gas (MMCFD)			1,490			1,410			1,462			1,416
Total Production (MBOED)			1,083			1,013			1,061			986
Average Sales Prices
Crude oil ($ per bbl)			$	80.75		93.19			75.77			98.64
Natural gas liquids ($ per bbl)			22.03			34.59			22.02			38.74
Natural gas ($ per MCF)			2.24			7.36			2.19			6.28

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 September 30, 2023, the Lower 48 contributed 65 percent of our consolidated liquids production and 77 percent of our consolidated natural gas production.

Net Income

Earnings from the Lower 48 decreased $872 million and $4,161 million in the three- and nine-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

• Higher DD&A expenses primarily due to higher rates from impacts to reserve revisions driven by higher operating costs and lower prices as well as higher production volumes.

• Higher production and operating expenses primarily due to increased well work activity, higher production volumes as well as increased electricity costs due to higher electricity rates.

Offsets to the earnings decrease include:

• Higher sales volumes.

• Gain on disposition primarily associated with the divestment of an equity investment and the absence of a loss on the sale of certain noncore assets in the third quarter of 2022.

In addition to the items mentioned above, in the nine-month period of 2023, earnings impacts include:

• Improved commercial performance and timing.

• Lower taxes other than income taxes driven by lower realized prices.

Production

Average production increased 70 MBOED and 75 MBOED in the three- and nine-month periods of 2023, respectively. Increases to production were primarily due to new wells online from our development programs in the Delaware Basin, Midland Basin, Eagle Ford and Bakken.

Offsets to the production increases were primarily due to normal field decline.

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Canada

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Income ($MM)			$	186		119			224			726
Average Net Production
Crude oil (MBD)			8			4			7			5
Natural gas liquids (MBD)			3			3			3			3
Bitumen (MBD)			64			69			66			65
Natural gas (MMCFD)			57			49			60			59
Total Production (MBOED)			85			84			86			83
Average Sales Prices
Crude oil ($ per bbl)			$	70.83		71.11			66.10			83.36
Natural gas liquids ($ per bbl)			26.26			29.62			24.09			39.24
Bitumen ($ per bbl)			57.85			49.77			42.03			63.14
Natural gas ($ per MCF)			0.67			2.40			2.05			3.47

Average sales prices include unutilized transportation costs.

Our Canadian operations mainly consist of the Surmont oil sands development in Alberta and the liquids-rich Montney unconventional play in British Columbia. As of September 30, 2023, Canada contributed six percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income

Earnings from Canada increased $67 million and decreased $502 million in the three- and nine-month periods of 2023, respectively. In the third-quarter, increases to earnings include:

• A $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit. See Note 20.

• Higher realized bitumen prices.

In addition to the items mentioned above, in the nine-month period of 2023, earnings impacts include:

• Lower realized year-to-date bitumen prices.

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

Production

Average production increased 1 MBOED and 3 MBOED in the three- and nine-month periods of 2023, respectively. Increases to production include new wells online from our development program in the Montney.

Offsets to the production increases include:

• Lower well performance at Surmont driven by a delayed start of the 2023 redrill program.

• Higher unplanned downtime due to facility constraints in the Montney.

In addition to the items mentioned above, in the nine-month period of 2023, production impacts include the absence of a planned turnaround at the Surmont Central Processing Facility 1 during the second quarter of 2022.

Surmont Acquisition

On October 4, 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont. Total consideration was approximately $2.7 billion of cash after customary adjustments, as well as future contingent payments of up to approximately $0.3 billion. Production from the acquired interest averaged approximately 66 MBD of bitumen in the first nine months of 2023. See Note 3.

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Results of Operations			Table of Contents

Europe, Middle East and North Africa

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Income ($MM)			$	253		922			882			1,719
Consolidated Operations
Average Net Production
Crude oil (MBD)			108			107			113			104
Natural gas liquids (MBD)			3			4			4			3
Natural gas (MMCFD)			264			331			297			323
Total Production (MBOED)			155			166			166			161
Average Sales Prices
Crude oil ($ per bbl)			$	87.45		102.70			83.37			103.03
Natural gas liquids ($ per bbl)			43.08			51.67			41.49			57.01
Natural gas ($ per MCF)			9.61			48.10			12.90			35.35

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, 2023, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 16 percent of our consolidated natural gas production.

Net Income

Earnings from Europe, Middle East and North Africa decreased by $669 million and $837 million in the three- and nine-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

• Lower commercial performance and timing.

• Lower sales volumes.

• Lower foreign exchange gains related to the USD strengthening against the NOK.

In addition to the items mentioned above, in the nine-month period of 2023, earnings decreased due to lower earnings from equity affiliates due to lower LNG sales prices.

Consolidated Production

Average consolidated production decreased 11 MBOED and increased 5 MBOED in the three- and nine-month periods of 2023, respectively. In the third-quarter decreases to production include:

• Normal field decline.

• Higher planned and unplanned downtime related to extended turnarounds across partner operated assets in Norway.

Offsets to the production decreases include:

• Additional interest acquired in Libya's Waha Concession in the fourth quarter of 2022.

• Absence of curtailed production in Libya due to the force majeure at the Es Sider export terminal for approximately three weeks in July 2022.

In addition to the items mentioned above, in the nine-month period of 2023, the production decreases were partially offset by improved well performance in Norway.

Exploration Activity

In the third quarter of 2023, we charged $37 million before-tax to dry hole expense for the Norwegian Warka suspended discovery well on license PL 1009.

First Production on Projects in Norway

In October 2023, we reached first production on several projects in Norway, including Tommeliten A and partner-operated Breidablikk and Kobra East & Gekko, all ahead of schedule.

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Results of Operations			Table of Contents

Asia Pacific

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Income ($MM)			$	465		520			1,374			2,181
Consolidated Operations
Average Net Production
Crude oil (MBD)			61			63			60			61
Natural gas (MMCFD)			42			80			46			135
Total Production (MBOED)			68			76			68			84
Average Sales Prices
Crude oil ($ per bbl)			$	89.10		108.99			83.95			110.25
Natural gas ($ per MCF)			3.77			4.18			4.08			6.05

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, 2023, Asia Pacific contributed five percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income

Earnings from Asia Pacific decreased $55 million and $807 million in the three- and nine-month periods of 2023, respectively. Decreases to earnings include:

• Lower earnings from equity affiliates due to lower LNG sales prices.

• Lower realized commodity prices.

Offsets to the earnings decreases include:

• Recognized $52 million tax benefit associated with deepwater tax incentives for Malaysia Block J. See Note 20.

• Lower taxes other than income taxes driven by lower realized commodity prices.

• Lower DD&A expenses primarily due to lower production volumes.

In addition to the items mentioned above, in the nine-month period of 2023, earnings impacts include:

• Decrease due to the absence of an after-tax gain of $534 million associated with the divestiture of our Indonesia assets in the first quarter of 2022.

• Decrease due to lower sales volumes primarily from the divestiture of our Indonesia assets in the first quarter of 2022.

Consolidated Production

Average consolidated production decreased 8 MBOED and 16 MBOED in the three- and nine-month periods of 2023, respectively. Decreases to production include:

• Normal field decline.

• Decrease in gas entitlement percentage and lower demand in Malaysia.

Offsets to the production decreases include:

• Bohai Bay development activity and production optimization in China.

• First production from development activity in Gumusut Phase 3 in Malaysia.

In addition to the items mentioned above, in the nine-month period of 2023, production also decreased due to the divestiture of our Indonesia assets in the first quarter of 2022.

Planned Acquisition

In March 2023, we announced that, subject to the closing of EIG's transaction with Origin Energy, we plan to take over operatorship of the upstream assets and purchase up to an additional 2.49 percent shareholding interest in Australia Pacific LNG Pty Ltd (APLNG). Both EIG's transaction with Origin Energy and our shareholder acquisition are subject to Australian regulatory approvals and other customary closing conditions. See Note 3.

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Penglai Phase 4B First Production in China

In October 2023, Phase 4B of the partner-operated Penglai 19-3 field in the Bohai Bay reached first production.

Other International

			Three Months Ended September 30						Nine Months Ended September 30
			2023			2022			2023			2022
Net Loss ($MM)			$	(2)		(28)			(5)			(28)

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
			2023			2022			2023			2022
Net Income (Loss)
Net interest expense			$	(91)		(125)			(267)			(507)
Corporate general and administrative expenses			(87)			(62)			(273)			(157)
Technology			(14)			(8)			(19)			41
Other income (expense)			(141)			(44)			(65)			581
			$	(333)		(239)			(624)			(42)

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense improved by $34 million and $240 million in the three- and nine-month periods of 2023, respectively, primarily due to higher interest income and lower interest expenses due to higher capitalized interest for longer term major projects.

Corporate G&A expenses include compensation programs and staff costs. Corporate G&A expenses increased $116 million in the nine-month period of 2023, primarily due to mark to market adjustments associated with certain compensation programs.

Technology includes our investments in low-carbon technologies as well as other new technologies or businesses and licensing revenues. Other new technologies or businesses and licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery, as well as LNG. Earnings from Technology decreased $60 million in the nine-month period of 2023, primarily due to lower licensing revenues. See Note 17.

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 third quarter of 2023, “Other” decreased $97 million primarily due to a consolidating tax adjustment and foreign exchange losses. In the nine-month period of 2023, "Other" decreased $646 million. In addition to the items mentioned above, decreases include the absence of a $474 million federal tax benefit, the absence of

$251 million gain associated with our CVE common shares, which were fully divested in the first quarter of 2022, and the absence of an after-tax gain of $62 million associated with debt restructuring transactions. The decreases were offset by the absence of $101 million tax impact associated with the disposition of our Indonesia assets in the first quarter of 2022. See Note 5 for information on our CVE common shares, Note 6 for information regarding our debt transactions and

Note 20 for information regarding income taxes.

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Capital Resources and Liquidity

Financial Indicators

			Millions of Dollars
			September 30 2023			December 31 2022
Cash and cash equivalents			$	8,830		6,458
Short-term investments			616			2,785
Total debt			19,063			16,643
Total equity			47,745			48,003
Percent of total debt to capital*			29		%	26
Percent of floating-rate debt to total debt			1		%	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 2023, the primary uses of our available cash were $8.4 billion to support our ongoing capital expenditures and investments program, $4.3 billion to repurchase common stock, and $4.2 billion to pay the ordinary dividend and VROC.

At September 30, 2023, we had total liquidity of $14.9 billion, comprised of cash and cash equivalents of $8.8 billion, short-term investments of $0.6 billion, and available borrowing capacity under our credit facility of $5.5 billion. 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 $14.7 billion for the first nine months of 2023, compared with $21.7 billion for the corresponding period of 2022. The decrease is primarily due to lower realized commodity prices across all products, partially offset by higher produced sales volumes in the Lower 48.

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 2023, we invested $8.4 billion in capital expenditures and investments. Our 2023 operating plan capital expenditures are currently expected to be between $10.8 billion to $11.2 billion. This guidance excludes any impact from the previously announced Surmont and APLNG transactions. Our 2022 capital expenditures and investments were $10.2 billion. See the “Capital Expenditures and Investments” section.

In the first nine months of 2023, we invested $1.1 billion in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4), and QatarEnergy LNG NFS(3) (NFS3). See Note 3.

Proceeds from asset sales were $0.6 billion in the first nine months of 2023 compared with $3.4 billion for the corresponding period in 2022. In the first nine months of 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of CVE, proceeds of $1.5 billion after customary adjustments, primarily from asset divestitures in our Asia Pacific and Lower 48 segments and $0.5 billion in contingent payments associated with prior divestitures. See Note 5.

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 within the year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities greater than one year.

Investing activities in the first nine months of 2023 included net sales of $1,860 million of investments. We had net sales of $2,433 million of short-term instruments and net purchases of $573 million of long-term instruments*.* See Note 14.

In July 2023, we executed an agreement to purchase the remaining 50 percent interest in Surmont from TotalEnergies EP Canada Ltd. In October, we completed this purchase for approximately $2.7 billion of cash after customary adjustments. See Note 3.

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, 2023.

In the third quarter of 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent interest in Surmont. See Note 3 and Note 6.

In the second quarter of 2023, we initiated and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases. These strategic transactions extended the weighted average maturity of our portfolio and reduced our near-term debt maturities. See Note 6.

Our debt balance at September 30, 2023 was $19.1 billion compared with $16.6 billion at December 31, 2022. The current portion of debt, including payments for finance leases, is $881 million. Payments are expected to be made using current cash balances and cash generated by operating activities.

In September 2023, 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 6 for additional information on debt and the revolving credit facility.

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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, 2023, and December 31, 2022, we had direct bank letters of credit of $398 million and $368 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of a credit rating downgrade, we may be required to post additional letters of credit.

Shelf Registration

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

Capital Requirements

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

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 2023 total return of capital is $11 billion.

In the first nine months of 2023, we paid ordinary dividends of $1.53 per common share and VROC payments of $1.90 per common share. In the first nine months of 2022, we paid ordinary dividends of $1.38 per common share and VROC payments of $1.20 per common share.

In November 2023, we declared an increase to our quarterly ordinary dividend from $0.51 per share to $0.58 per share, representing a 14 percent increase. The ordinary dividend of $0.58 per share is payable December 1, 2023, to shareholders of record on November 14, 2023. Beginning in the first quarter of 2024, ConocoPhillips plans to pay its quarterly ordinary dividend and VROC concurrently, and will announce such payments in the same quarter they will be paid.

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 September 30, 2023, share repurchases since the inception of our current program totaled 374.0 million shares and $27.7 billion. In the nine months ended September 30, 2023, we repurchased 39.2 million shares for a cost of $4.3 billion.

See Part I—Item 1A—Risk Factors – “Our ability to execute our capital return program is subject to certain considerations” in our 2022 Annual Report on Form 10-K.

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Capital Expenditures and Investments

			Millions of Dollars
			Nine Months Ended September 30
			2023			2022
Alaska			$	1,140		740
Lower 48			4,878			4,120
Canada			345			382
Europe, Middle East and North Africa			834			531
Asia Pacific			245			1,791
Other International			—			—
Corporate and Other			923			62
Capital expenditures and investments			$	8,365		7,626

During the first nine months of 2023, capital expenditures and investments supported key operating activities and acquisitions, primarily:

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

• Development 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 oil sands in Canada.

• Development activities across assets in Norway.

• Continued development activities in Malaysia and China.

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

Our 2023 operating plan capital expenditure guidance is currently expected to be $10.8 billion to $11.2 billion. This guidance excludes any impact from the previously announced Surmont and APLNG transactions. Our operating plan capital was $10.2 billion in 2022.

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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, 2023
Revenues and Other Income			$	28,107
Income before income taxes*			8,002
Net Income			7,950

*Includes approximately $5.7 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

			Millions of Dollars
			September 30, 2023			December 31, 2022
Current assets			$	9,650		10,766
Amounts due from Non-Obligated Subsidiaries, current			1,465			1,892
Noncurrent assets			85,318			79,269
Amounts due from Non-Obligated Subsidiaries, noncurrent			8,179			6,552
Current liabilities			6,939			8,201
Amounts due to Non-Obligated Subsidiaries, current			3,323			3,248
Noncurrent liabilities			46,842			40,389
Amounts due to Non-Obligated Subsidiaries, noncurrent			28,860			24,594

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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 54–56 of our 2022 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, 2023, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

For remediation activities in the U.S. and Canada, our consolidated balance sheet included a total environmental accrual of $187 million at September 30, 2023, compared with $182 million at December 31, 2022. 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 2022 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 56–57 of our 2022 Annual Report on Form 10-K.

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Company Response to Climate-Related Risks

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

In 2020, we became the first U.S.-based oil and gas company to adopt a Paris-aligned climate-risk strategy with an ambition to become a net-zero company for operational (Scope 1 and 2) emissions by 2050. The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and better equip the company to respond to evolving investor sentiment, technologies for emissions reduction, alternative energy technologies and uncertainties such as government policies. The strategy sets out our choices around portfolio composition, emissions reductions, targets and incentives, emissions-related technology development, and our climate-related policy and financial sector engagement.

In early 2022, we published our Plan for the Net-Zero Energy Transition (the 'Plan'), to outline how we intend to apply our strategic capabilities and resources to meet the challenges posed by climate change in an economically viable, accountable and actionable way that balances the interests of our stakeholders. Progress on the Plan can be found in our 2022 Sustainability Report.

Key elements of our plan include:

• Maintain strategic flexibility:

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

◦Commit to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the primary 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.

• Reduce Scope 1 and 2 emissions:

◦Set 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.

• Address Scope 3 emissions:

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

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

• Contribute to the energy transition:

◦Build an attractive LNG portfolio.

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

Our Plan recognizes the importance of reducing society’s end-use emissions to meet global climate goals. As an upstream producer, we do not control how the commodities we sell into global markets are converted into different energy products or selected for use by consumers. This is why we have consistently taken a prominent role in advocating for a well-designed, economy-wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions. We have also expanded policy advocacy beyond carbon pricing to include regulatory action, such as support for the direct regulation of methane.

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 capital and could subject us to litigation" in our 2022 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 “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, or from a public health crisis or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes.

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

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

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

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

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

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

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

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

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

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

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

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

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• 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 2022 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

			ConocoPhillips 2023 Q3 10-Q			48

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