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 and Asia; LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at June 30, 2023, we employed approximately 9,700 people worldwide and had total assets of $90 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 conflict in Ukraine, 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 the second quarter of 2023, we completed a strategic debt refinancing that extends the weighted average maturity of our portfolio from 15 years to 17 years and reduces near term debt maturities. See Note 6.

In July, as a part of ongoing portfolio optimization geared towards our returns-focused value proposition, we executed an agreement to purchase the remaining 50 percent interest in Surmont, an asset in our Canada segment. Surmont's long life and durable, low cost of supply barrels play an important role in our portfolio. The transaction is expected to close in the second half of 2023, subject to regulatory approvals and other customary closing conditions. Upon close, 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.

			ConocoPhillips 2023 Q2 10-Q			26

Management’s Discussion and Analysis			Table of Contents

As the energy transition continues, we expect demand for lower GHG intensity fuels, such as LNG, to grow to displace coal. In the second quarter of 2023, we continued pursuing expansion of our global LNG portfolio. In June, we closed on the formation of the North Field South (NFS) joint venture, Qatar Liquefied Gas Company Limited (12) (QG12). Participation in the Qatar Liquefied Gas Company Limited (8) (QG8) (North Field East) and QG12 joint ventures will add approximately 2 MTPA net to ConocoPhillips. See Note 4. Additionally, we signed 20-year offtake agreements 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.

In August, we reconfirmed our 2023 planned return of capital to shareholders of $11 billion through our three-tier return of capital framework, significantly exceeding our goal of 30 percent of our anticipated cash provided by operating activities for the full year. We also declared an ordinary dividend of $0.51 per share and a fourth-quarter VROC payment of $0.60 per share.

Operationally, we remain focused on safely executing the business. Production was 1,805 MBOED in the second quarter of 2023, an increase of 113 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, second-quarter 2023 production increased by 100 MBOED or six 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.

Second-quarter production resulted in $3.9 billion of cash provided by operating activities. We returned $1.3 billion to shareholders through share repurchases and $1.4 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents and short-term investments totaling $6.8 billion.

We re-invested $2.9 billion into the business in the form of capital expenditures and investments during the second quarter of 2023, 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.

27			ConocoPhillips 2023 Q2 10-Q

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 $78.39 per barrel in the second quarter of 2023, a decrease of 31 percent compared with $113.78 per barrel in the second quarter of 2022. WTI at Cushing crude oil prices averaged $73.78 per barrel in the second quarter of 2023, a decrease of 32 percent compared with $108.41 per barrel in the second quarter of 2022. Oil prices decreased due to persistent macroeconomic headwinds and refinery outages impacting demand concurrent with higher global supplies versus the prior year.

Henry Hub natural gas prices averaged $2.09 per MMBTU in the second quarter of 2023, a decrease of 71 percent compared with $7.17 per MMBTU in the second quarter of 2022. Henry Hub prices decreased due to higher North American production concurrent with excess inventories following a mild winter.

Our realized bitumen price averaged $41.01 per barrel in the second quarter of 2023, a decrease of 46 percent compared with $75.42 per barrel in the second quarter of 2022. The decrease in the second quarter of 2023 was driven by lower blend prices for Surmont sales, largely attributed to a weakening of WTI price and widening WCS differentials. WCS differentials widened due to weaker demand at the U.S. Gulf Coast. We continue to optimize bitumen price realizations through diluent recovery unit operating improvements as well as blending and transportation strategies.

For the second quarter of 2023, our total average realized price was $54.50 per BOE compared with $88.57 per BOE in the second quarter of 2022.

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Management’s Discussion and Analysis			Table of Contents

Key Operating and Financial Summary

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

• Delivered record company and Lower 48 production of 1,805 MBOED and 1,063 MBOED, respectively.

• Executed agreement to purchase the remaining 50% interest in Surmont, subject to regulatory approvals and other closing conditions.

• Completed acquisition of an equity interest in Qatar's NFS project.

• Signed 20-year offtake agreements at the Saguaro LNG export facility on the west coast of Mexico for approximately 2.2 MPTA, subject to Mexico Pacific reaching FID.

• Generated cash provided by operating activities of $3.9 billion.

• Distributed $2.7 billion to shareholders through a three-tier framework, including $1.4 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 $6.0 billion and short-term investments of $1.1 billion.

Outlook

Production, Capital and DD&A

Third-quarter 2023 production is expected to be 1.78 to 1.82 MMBOED. Full-year production guidance is now expected to be 1.80 to 1.81 MMBOED, as compared to prior guidance of 1.78 to 1.80 MMBOED.

2023 capital guidance has been narrowed to $10.8 billion to $11.2 billion versus the prior guidance of $10.7 billion to $11.3 billion reflecting ongoing progress on the company's development plans.

2023 guidance for DD&A has increased from $8.1 billion to $8.2 billion.

All guidance excludes any impact from the previously announced Surmont and APLNG 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 six-month periods ended June 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 June 30									Six Months Ended June 30
			2023			2022						2023			2022
Alaska			$	372		687						788			1,271
Lower 48			1,230			3,581						3,082			6,371
Canada			32			316						38			607
Europe, Middle East and North Africa			264			385						629			797
Asia Pacific			387			525						909			1,661
Other International			(4)			—						(3)			—
Corporate and Other			(49)			(349)						(291)			197
Net income			$	2,232		5,145						5,152			10,904

Net income in the second quarter of 2023 decreased $2,913 million. Second quarter earnings were negatively impacted by:

• Lower realized commodity prices.

• Absence of gains from dispositions related to the sale of certain noncore assets in the Lower 48 segment as well as contingent payments associated with previous asset sales.

• Higher DD&A expenses primarily due to higher overall production volumes and higher rates from impacts to reserve revisions driven by higher operating expenses.

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

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

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.

Net income in the six-month period ended June 30, 2023, decreased $5,752 million. In addition to the items mentioned above, earnings in the six-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 19.

• Absence of gains from dispositions associated with the divestiture of our Indonesia assets in the first quarter of 2022.

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

Offsets to the earnings decreases in the six-month period include improved commercial performance and timing.

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 six-month periods of 2023 decreased $8,810 million and $11,761 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 six-month period also include the impact of the divestiture of our Indonesia assets in the first quarter of 2022.

Equity in earnings of affiliates in the second quarter of 2023 decreased $112 million due to lower earnings primarily driven by lower LNG and crude prices*.*

Gain (loss) on dispositions for the three- and six-month periods of 2023 decreased $263 million and $987 million, respectively, primarily due to the absence of gains associated with the divestiture of noncore assets in the Lower 48 segment in the second quarter of 2022, the absence of contingent payments associated with previous dispositions in our Canada and Lower 48 segments as well as the divestiture of our Indonesia assets in the first quarter of 2022.

Purchased commodities for the three- and six-month periods of 2023 decreased $4,618 million and $5,231 million, respectively, primarily due to lower prices across all commodities in the U.S. and Europe.

Production and operating expenses for the three- and six-month periods of 2023 increased $145 million and $343 million, respectively, primarily due to higher production volumes in the Lower 48 segment and increased well work activity.

Selling, general and administrative expenses increased $109 million in the second quarter of 2023 primarily due to mark to market adjustments associated with certain compensation programs.

DD&A expenses for the three- and six-month periods of 2023 increased $200 million and $319 million, respectively, mainly due to higher overall production volumes primarily due to development in the Lower 48 segment and higher rates from impacts to reserve revisions driven by higher operating expenses, partially offset by the absence of DD&A from disposed assets.

Taxes other than income taxes for the three- and six-month periods of 2023 decreased $508 million and $746 million, respectively, driven by lower commodity prices, partially offset by higher production volumes.

Other expenses decreased $109 million in the second quarter of 2023 primarily related to the absence of premiums paid to repurchase debt in the second quarter of 2022 as well as a gain of $27 million associated with extinguishment of debt in the second quarter of 2023.

See Note 19—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 June 30						Six Months Ended June 30
			2023			2022			2023			2022
Average Net Production
Crude oil (MBD)
Consolidated operations			918			857			922			880
Equity affiliates			13			14			12			13
Total crude oil			931			871			934			893
Natural gas liquids (MBD)
Consolidated operations			275			236			270			227
Equity affiliates			8			8			7			7
Total natural gas liquids			283			244			277			234
Bitumen (MBD)			66			59			67			63
Natural gas (MMCFD)
Consolidated operations			1,896			1,872			1,909			1,999
Equity affiliates			1,251			1,235			1,209			1,181
Total natural gas			3,147			3,107			3,118			3,180
Total Production (MBOED)			1,805			1,692			1,798			1,720

			Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations			$	74.18		111.49			75.85			102.97
Equity affiliates			75.10			111.97			77.90			105.20
Total crude oil			74.19			111.50			75.88			103.00
Natural gas liquids (per bbl)
Consolidated operations			20.05			42.20			22.41			41.61
Equity affiliates			43.62			72.44			50.13			69.99
Total natural gas liquids			20.72			43.26			23.18			42.57
Bitumen (per bbl)			41.01			75.42			34.93			70.25
Natural gas (per MCF)
Consolidated operations			2.89			10.19			4.27			9.46
Equity affiliates			8.23			10.08			9.06			9.51
Total natural gas			5.04			10.15			6.16			9.48

			Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental and other			$	49		46			119			108
Leasehold impairment			11			10			30			16
Dry holes			23			87			72			88
			$	83		143			221			212

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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 June 30, 2023, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.

Total production of 1,805 MBOED increased 113 MBOED or 7 percent in the second quarter of 2023 and 78 MBOED or 5 percent in the six-month period of 2023, primarily due to new wells online in the Lower 48, Alaska, Australia, Canada, China, Malaysia and Libya.

Production increases in the second quarter of 2023 were partially offset due to normal field decline.

After adjusting for impacts from closed acquisitions and dispositions, second-quarter 2023 production increased by 100 MBOED or six 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.

Production for the first six months of 2023 was 1,798 MBOED, an increase of 78 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, production increased 82 MBOED or five 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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Results of Operations			Table of Contents

Segment Results

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

Alaska

			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income ($MM)			$	372		687			788			1,271
Average Net Production
Crude oil (MBD)			176			177			177			180
Natural gas liquids (MBD)			16			16			18			17
Natural gas (MMCFD)			34			34			38			34
Total Production (MBOED)			198			199			201			203
Average Sales Prices
Crude oil ($ per bbl)			$	76.09		114.77			79.08			105.26
Natural gas ($ per MCF)			4.38			3.34			4.49			3.66

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of June 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 $315 million and $483 million in the three- and six-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.

Production

Average production decreased 1 MBOED and 2 MBOED in the three- and six-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 June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income ($MM)			$	1,230		3,581			3,082			6,371
Average Net Production
Crude oil (MBD)			565			528			563			533
Natural gas liquids (MBD)			252			214			245			203
Natural gas (MMCFD)			1,478			1,411			1,448			1,419
Total Production (MBOED)			1,063			977			1,049			972
Average Sales Prices
Crude oil ($ per bbl)			$	72.06		109.14			73.19			101.34
Natural gas liquids ($ per bbl)			19.61			42.00			22.01			41.26
Natural gas ($ per MCF)			1.43			6.85			2.16			5.74

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 June 30, 2023, the Lower 48 contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.

Net Income

Earnings from the Lower 48 decreased $2,351 million and $3,289 million in the three- and six-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

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

• Higher production and operating expenses primarily due to higher production volumes, increased well work activity and inflation.

• Absence of gains on disposition of $63 million related to the sale of certain noncore assets as well as contingent payments associated with previous asset sales.

Offsets to the earnings decrease include:

• Higher sales volumes.

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

In addition to the items mentioned above, in the six-month period of 2023, earnings impacts include higher earnings associated with improved commercial performance and timing.

Production

Average production increased 86 MBOED and 77 MBOED in the three- and six-month periods of 2023, 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.

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

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Canada

			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income ($MM)			$	32		316			38			607
Average Net Production
Crude oil (MBD)			6			5			6			6
Natural gas liquids (MBD)			3			3			3			3
Bitumen (MBD)			66			59			67			63
Natural gas (MMCFD)			58			66			61			65
Total Production (MBOED)			85			78			87			83
Average Sales Prices
Crude oil ($ per bbl)			$	59.40		94.79			62.56			88.04
Natural gas liquids ($ per bbl)			17.11			44.93			22.94			43.44
Bitumen ($ per bbl)			41.01			75.42			34.93			70.25
Natural gas ($ per MCF)			0.56			4.47			2.70			3.88

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 June 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 decreased $284 million and $569 million in the three- and six-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

• The 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 7 MBOED and 4 MBOED in the three- and six-month periods of 2023, respectively. Increases to production include:

• Absence of a planned turnaround at the Surmont Central Processing Facility 1 during the second quarter of 2022.

• New wells online from our development program in the Montney.

Offsets to the production increases include downtime and normal field decline.

Planned Acquisition

In July 2023, we executed an agreement to purchase the remaining 50 percent interest in the Surmont asset. The effective date is April 1, 2023 with closing expected in the second half of 2023. This transaction is subject to regulatory approvals and other customary closing conditions. See Note 3.

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Results of Operations			Table of Contents

Europe, Middle East and North Africa

			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income ($MM)			$	264		385			629			797
Consolidated Operations
Average Net Production
Crude oil (MBD)			113			90			116			101
Natural gas liquids (MBD)			4			3			4			4
Natural gas (MMCFD)			286			306			313			318
Total Production (MBOED)			165			144			172			158
Average Sales Prices
Crude oil ($ per bbl)			$	79.64		115.61			81.48			103.21
Natural gas liquids ($ per bbl)			37.06			68.00			40.63			60.49
Natural gas ($ per MCF)			10.83			28.32			14.31			28.77

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 June 30, 2023, our Europe, Middle East and North Africa operations contributed 10 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 $121 million and $168 million in the three- and six-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

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

• Less foreign exchange gains related to the USD strengthening against the Norwegian Kroner.

Offsets to the earnings decreases include:

• Improved commercial performance and timing.

• Absence of the establishment of a valuation allowance against certain deferred tax assets associated with changes to the Petroleum Tax System in Norway in the second quarter of 2022.

Consolidated Production

Average consolidated production increased 21 MBOED and 14 MBOED in the three- and six-month periods of 2023, respectively. Increases to production include:

• Absence of fieldwide turnarounds in the Greater Ekofisk Area of Norway in the second quarter of 2022.

• Additional interest acquired in Libya's Waha Concession that increased our interest 4.1 percent to 20.4 percent in the fourth quarter of 2022.

• Improved well performance in Norway.

Offsets to the production increases include normal field decline.

Qatar Interest

During 2022, we were awarded a 25 percent interest in QG12, a new joint venture with QatarEnergy to participate in the NFS LNG project. Formation of QG12 closed in June 2023. See Notes 3 and 4.

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Results of Operations			Table of Contents

Asia Pacific

			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income ($MM)			$	387		525			909			1,661
Consolidated Operations
Average Net Production
Crude oil (MBD)			58			57			60			60
Natural gas (MMCFD)			40			55			49			163
Total Production (MBOED)			65			66			68			87
Average Sales Prices
Crude oil ($ per bbl)			$	78.64		117.14			81.07			110.89
Natural gas ($ per MCF)			4.10			4.17			4.22			6.53

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 June 30, 2023, Asia Pacific contributed five percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Net Income

Earnings from Asia Pacific decreased $138 million and $752 million in the three- and six-month periods of 2023, respectively. Decreases to earnings include:

• Lower realized commodity prices.

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

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

In addition to the items mentioned above, in the six-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 driven by the divestiture of our Indonesia assets in the first quarter of 2022.

Consolidated Production

Average consolidated production decreased 1 MBOED and 19 MBOED in the three- and six-month periods of 2023, respectively. Decreases to production were primarily due to normal field decline.

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 six-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 intend 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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Results of Operations			Table of Contents

Other International

			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Loss ($MM)			$	(4)		—			(3)			—

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

Corporate and Other

			Millions of Dollars
			Three Months Ended June 30						Six Months Ended June 30
			2023			2022			2023			2022
Net Income (Loss)
Net interest expense			$	(86)		(164)			(176)			(382)
Corporate general and administrative expenses			(96)			(16)			(186)			(95)
Technology			(11)			(9)			(5)			49
Other income (expense)			144			(160)			76			625
			$	(49)		(349)			(291)			197

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense improved by $78 million and $206 million in the three- and six-month periods of 2023, respectively, primarily due to higher interest income as well as lower interest expenses.

Corporate G&A expenses include compensation programs and staff costs. Corporate G&A expenses increased $80 million and $91 million in the three- and six-month periods of 2023, respectively, primarily due to mark to market adjustments associated with certain compensation programs.

Technology includes our investment 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. See Note 16. Earnings from Technology decreased $54 million in the six-month period of 2023, primarily due to 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. In the second quarter of 2023, “Other” increased $304 million primarily due to a consolidating tax adjustment, the absence of premiums paid on the early retirement of debt in 2022 coupled with a gain on the early retirement of debt in 2023 and foreign exchange impacts. In the six-month period of 2023, "Other" decreased $549 million. 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 increases described above as well as 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 19 for information regarding income taxes.

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Capital Resources and Liquidity

Financial Indicators

			Millions of Dollars
			June 30 2023			December 31 2022
Cash and cash equivalents			$	5,735		6,458
Short-term investments			1,080			2,785
Total debt			16,444			16,643
Total equity			47,531			48,003
Percent of total debt to capital*			26		%	26
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 six months of 2023, the primary uses of our available cash were $5.8 billion to support our ongoing capital expenditures and investments program, $3.0 billion to repurchase common stock, and $2.8 billion to pay the ordinary dividend and VROC.

At June 30, 2023, we had total liquidity of $12.3 billion, comprised of cash and cash equivalents of $5.7 billion, short-term investments of $1.1 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 $9.3 billion for the first six months of 2023, compared with $13.0 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 six months of 2023, we invested $5.8 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 six months of 2023, we invested $0.9 billion in LNG projects, including PALNG, QG8, and QG12. See Note 3.

Proceeds from asset sales were $0.4 billion in the first six months of 2023 compared with $3.0 billion for the corresponding period in 2022. In the first six months of 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of CVE, proceeds of $1.2 billion primarily from asset divestitures in our Asia Pacific and Lower 48 segments after customary adjustments and $0.4 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, as well as debt securities classified as available for sale. Funds for short-term needs to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities within the year. Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities greater than one year.

Investing activities in the first six months of 2023 included net sales of $1,549 million of investments. We had net sales of $1,893 million of short-term instruments and net purchases of $344 million of long-term instruments*.* See Note 13.

In July 2023, we executed an agreement to purchase the remaining 50 percent interest in Surmont from TotalEnergies EP Canada Ltd. for approximately $4.0 billion CAD ($3.0 billion), subject to customary adjustments. The transaction is subject to contingent payments for a five-year term of up to approximately $440 million CAD ($325 million), subject to certain production targets being achieved. Closing of this transaction is anticipated in the second half of 2023, subject to regulatory approvals and other customary closing conditions.

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 June 30, 2023.

In the second quarter of 2023, we initiated and completed concurrent debt transactions as part of our debt refinancing strategy that extends the weighted average maturity of our portfolio from 15 years to 17 years and reduces our near-term debt maturities. The refinancing consisted of tender offers to repurchase existing debt with cash and a new debt issuance to fund the repurchase. See Note 6.

Our debt balance at June 30, 2023 was $16.4 billion compared with $16.6 billion at December 31, 2022. The current portion of debt, including payments for finance leases, is $879 million. Payments are expected to be made using current cash balances and cash generated by operating activities.

In May 2023, S&P 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 June 30, 2023, and December 31, 2022, we had direct bank letters of credit of $261 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 six months of 2023, we paid ordinary dividends of $1.02 cents per common share and VROC payments of $1.30 cents per common share. In the first six months of 2022, we paid ordinary dividends of $0.92 cents per common share and VROC payments of $0.50 cents per common share.

In August 2023, we declared both an ordinary dividend of $0.51 cents per share and a VROC payment of $0.60 cents per share. The ordinary dividend of $0.51 cents per share is payable September 1, 2023, to shareholders of record on August 16, 2023. The VROC of $0.60 cents per share is payable October 16, 2023, to shareholders of record on September 28, 2023.

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 June 30, 2023, share repurchases since the inception of our current program totaled 362.9 million shares and $26.4 billion. In the six months ended June 30, 2023, we repurchased 28.1 million shares for a cost of $3.0 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
			Six Months Ended June 30
			2023			2022
Alaska			$	769		471
Lower 48			3,357			2,347
Canada			228			247
Europe, Middle East and North Africa			567			364
Asia Pacific			142			1,664
Other International			—			—
Corporate and Other			757			36
Capital expenditures and investments			$	5,820		5,129

During the first six 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, QG8, and QG12.

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
			Six Months Ended June 30, 2023
Revenues and Other Income			$	18,194
Income before income taxes*			5,098
Net Income			5,152

*Includes approximately $3.6 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

			Millions of Dollars
			June 30, 2023			December 31, 2022
Current assets			$	7,254		10,766
Amounts due from Non-Obligated Subsidiaries, current			1,559			1,892
Noncurrent assets			86,501			79,269
Amounts due from Non-Obligated Subsidiaries, noncurrent			7,752			6,552
Current liabilities			6,078			8,201
Amounts due to Non-Obligated Subsidiaries, current			2,771			3,248
Noncurrent liabilities			46,702			40,389
Amounts due to Non-Obligated Subsidiaries, noncurrent			31,465			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 June 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 balance sheet included a total environmental accrual of $185 million at June 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 focusing on GHG emissions reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. 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. A progress report on the Plan was published in March 2023.

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 our total production is ultimately processed into consumer products. 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 conflict between Russia and Ukraine, and the global response to such conflict, security threats on facilities and infrastructure, or from a public health crisis or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• Volatility in the commodity futures markets.

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

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

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

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

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

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

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

• The operation and financing of our joint ventures.

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

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

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

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

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

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

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