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 45**.

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 March 31, 2023, we employed approximately 9,600 people worldwide and had total assets of $91 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. During the first quarter of 2023, commodity prices decreased as compared with the prior periods, largely due to weak macroeconomic sentiment and a mild winter across the Northern Hemisphere moderating demand.

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.

As the energy transition continues, we anticipate increasing demand for lower GHG intensity fuels to displace coal and work with intermittent renewables to meet energy demand. In the first quarter of 2023, we continued to expand upon our global LNG portfolio. As a result of the first phase of the Port Arthur LNG project ("Phase 1") reaching FID, in March, we acquired a 30 percent direct equity holding in Port Arthur Liquefaction Holdings, LLC (PALNG), a joint venture for the development of a large-scale LNG facility. Phase 1 will include two natural gas liquefaction trains and LNG storage tanks, as well as associated facilities capable of producing, under optimal conditions, up to 13.5 MTPA of LNG. In addition, we entered into a 20-year agreement to purchase 5 MTPA of LNG offtake at the start of Phase 1 and a natural gas supply management agreement, whereby we will manage the feedgas supply requirements for Phase 1. See Note 3.

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Management’s Discussion and Analysis			Table of Contents

Also in March, 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 (APLNG). Both EIG's transaction with Origin Energy and our shareholder acquisition are subject to Australian regulatory approvals and other customary closing conditions.

In March, we also received the Department of the Interior's Record of Decision regarding our planned Willow project in Alaska. The decision adopted the BLM's Alternative E, which consists of three core pads. This oil project will leverage both our existing pipeline infrastructure and experience as a proven operator in Alaska, and is designed to limit our footprint in the National Petroleum Reserve Alaska.

In March, we reaffirmed our commitment to ESG and our Paris-aligned climate-risk strategy by publishing a progress report associated with our Plan for the Net-zero Energy Transition. In April, we announced that we are accelerating our operational GHG emissions intensity reduction target through 2030. We are now targeting a reduction in gross operated and net equity operational emissions intensity of 50-60 percent from 2016 levels by 2030, an improvement from the previously announced target of 40-50 percent. In addition, we continue to evaluate low-carbon options in Hydrogen and CCS that align with our disciplined investment criteria. See "Contingencies —Company Response to Climate-Related Risks".

Demonstrating our commitment to enhancing balance sheet strength, we remain dedicated to achieving our previously announced $5 billion debt reduction target that we announced in 2021. Through the first quarter of 2023, we have reduced our debt by $3.3 billion. See Note 5.

In April, we reconfirmed our 2023 planned return of capital to shareholders of $11 billion, based on $80 WTI, 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. In May, we declared an ordinary dividend of $0.51 per share and a third-quarter VROC payment of $0.60 per share.

Operationally, we remain focused on safely executing the business. Production was 1,792 MBOED in the first quarter of 2023, an increase of 45 MBOED from the same period a year ago. After adjusting for impacts from closed acquisitions and dispositions, first-quarter 2023 production increased by 65 MBOED or 4 percent from the same period a year ago. This was primarily driven by new wells online in the Lower 48 and improved well performance across the portfolio, partially offset by normal field decline and downtime.

First quarter production resulted in $5.4 billion of cash provided by operating activities. We returned $1.7 billion to shareholders through share repurchases and $1.5 billion through our ordinary dividend and a VROC. We ended the quarter with cash, cash equivalents and short-term investments totaling $8.6 billion.

We re-invested $2.9 billion into the business in the form of capital expenditures and investments during the first quarter of 2023, with over half of the expenditures focused on flexible, short-cycle unconventional plays in the Lower 48 segment, where our production has access to both domestic and export markets. This also includes approximately $0.4 billion associated with our PALNG investment reported in the Corporate and Other segment.

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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 are 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 $81.27 per barrel in the first quarter of 2023, a decrease of 20 percent compared with $101.40 per barrel in the first quarter of 2022. WTI at Cushing crude oil prices averaged $76.13 per barrel in the first quarter of 2023, a decrease of 19 percent compared with $94.29 per barrel in the first quarter of 2022. Oil prices decreased due to persistent recession fears and an unusually heavy global refinery maintenance season impacting demand.

Henry Hub natural gas prices averaged $3.44 per MMBTU in the first quarter of 2023, a decrease of 31 percent compared with $4.96 per MMBTU in the first quarter of 2022. Henry Hub prices have decreased due to rising U.S. gas production and seasonally soft demand stemming from milder winter weather.

Our realized bitumen price averaged $29.49 per barrel in the first quarter of 2023, a decrease of 55 percent compared with $65.86 per barrel in the first quarter of 2022. The decrease in the first 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 for heavy oil 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 first quarter of 2023, our total average realized price was $60.86 per BOE compared with $76.99 per BOE in the first quarter of 2022.

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Management’s Discussion and Analysis			Table of Contents

Key Operating and Financial Summary

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

• Delivered record company and Lower 48 segment production of 1,792 MBOED and 1,036 MBOED, respectively;

• Distributed $3.2 billion to shareholders through a three-tier return of capital framework, including $1.7 billion through share repurchases and $1.5 billion through the ordinary dividend and VROC;

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

• Ended the quarter with cash, cash equivalents, restricted cash and short-term investments of $8.9 billion;

• Acquired 30 percent equity interest in Port Arthur LNG joint venture upon FID for Phase 1;

• Commenced construction on the Willow project after receiving a positive record of decision from the U.S. Department of the Interior approving a development plan with three core pads;

• Announced plans to assume upstream operatorship of APLNG following the closing of EIG's transaction with Origin Energy and acquire up to an additional 2.49 percent shareholding interest, subject to regulatory approvals and customary closing conditions;

• Accelerated the company's GHG emissions-intensity reduction target through 2030 from 40-50 percent to 50-60 percent, using a 2016 baseline.

Outlook

Production

Second-quarter 2023 production is expected to be 1.77 to 1.81 MMBOED. The company raised full-year production guidance midpoint by 10 MBOED. Full-year production is now expected to be 1.78 to 1.80 MMBOED, as compared to prior guidance of 1.76 to 1.80 MMBOED.

All other guidance items remain unchanged.

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Results of Operations			Table of Contents

Results of Operations

Unless otherwise indicated, discussion of consolidated results for the three-month period ended March 31, 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 March 31
			2023			2022
Alaska			$	416		584
Lower 48			1,852			2,790
Canada			6			291
Europe, Middle East and North Africa			365			412
Asia Pacific			522			1,136
Other International			1			—
Corporate and Other			(242)			546
Net income			$	2,920		5,759

Net income in the first quarter of 2023 decreased $2,839 million. First quarter earnings were negatively impacted by:

• Lower realized commodity prices.

• Absence of a $515 million tax benefit related to the closing of an IRS audit in the first quarter of 2022. See Note 18.

• Absence of gains from dispositions associated with the divestiture of our Indonesia assets in the first quarter of 2022 as well as contingent payments from prior dispositions.

• Absence of gains associated with our Cenovus Energy (CVE) common shares which were fully divested in the first quarter of 2022. See Note 4.

• Higher production and operating expenses primarily driven by higher production volumes in addition to higher well work activity and inflation.

• Higher DD&A expenses primarily due to higher overall production volumes and higher rates from impacts to reserve revisions driven by higher operating expenses at year-end 2022, partially offset by the absence of DD&A from disposed assets.

• The absence of an after-tax gain of $62 million associated with 2022 refinancing transactions.

Offsets to the earnings decreases include:

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

• Improved commercial performance and timing.

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

See the “Segment Results” section for additional information.

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Income Statement Analysis

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

Sales and other operating revenues decreased $2,951 million primarily due to lower realized commodity prices and the impact of divestitures of Indonesia and noncore assets in the Lower 48 segment, partially offset by higher sales volumes driven primarily by development in the Lower 48 segment.

Gain on dispositions in the first quarter of 2023 decreased primarily due to the absence of gains associated with 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 segment.

Other income decreased $172 million primarily due to the absence of gains associated with our CVE common shares, which were fully divested in the first quarter of 2022. See Note 4.

Purchased commodities decreased $613 million primarily due to lower commodity prices and gas volumes partially offset by higher crude volumes.

Production and operating expenses increased $198 million primarily due to higher production volumes in addition to higher well work activity and inflation.

DD&A expenses increased $119 million 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 at year-end 2022, partially offset by the absence of DD&A from disposed assets.

Taxes other than income taxes decreased $238 million driven by lower commodity prices, partially offset by higher production volumes.

Other expenses increased $146 million primarily related to the absence of a gain of $127 million associated with extinguishment of debt from the first quarter of 2022.

See Note 18—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 March 31
			2023			2022
Average Net Production
Crude oil (MBD)
Consolidated operations			926			903
Equity affiliates			11			12
Total crude oil			937			915
Natural gas liquids (MBD)
Consolidated operations			264			216
Equity affiliates			7			7
Total natural gas liquids			271			223
Bitumen (MBD)			69			67
Natural gas (MMCFD)
Consolidated operations			1,922			2,126
Equity affiliates			1,166			1,127
Total natural gas			3,088			3,253
Total Production (MBOED)			1,792			1,747

			Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations			$	77.60		94.79
Equity affiliates			80.97			97.20
Total crude oil			77.65			94.82
Natural gas liquids (per bbl)
Consolidated operations			24.97			40.95
Equity affiliates			57.71			67.04
Total natural gas liquids			25.84			41.80
Bitumen (per bbl)			29.49			65.86
Natural gas (per MCF)
Consolidated operations			5.65			8.81
Equity affiliates			9.95			8.86
Total natural gas			7.30			8.83

			Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental and other			$	70		62
Leasehold impairment			19			6
Dry holes			49			1
			$	138		69

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We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. At March 31, 2023, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar and Libya.

Total production of 1,792 MBOED increased 45 MBOED or 3 percent in the first quarter of 2023, primarily due to:

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

• Additional working interest acquired in the first quarter of 2022 at APLNG in Asia Pacific.

Production increases in the first quarter of 2023 were partly offset due to:

• Normal field decline.

• Divestitures of Indonesia and noncore assets in the Lower 48 segment.

After adjusting for impacts from closed acquisitions and dispositions, first-quarter 2023 production increased by 65 MBOED or 4 percent from the same period a year ago. This was primarily driven by new wells online in the Lower 48 and improved well performance across the portfolio, partially offset by 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-month period ended March 31, 2023, is based on a comparison with the corresponding period of 2022 and are shown after-tax.

Alaska

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	416		584
Average Net Production
Crude oil (MBD)			179			182
Natural gas liquids (MBD)			18			18
Natural gas (MMCFD)			42			35
Total Production (MBOED)			204			206
Average Sales Prices
Crude oil ($ per bbl)			$	82.22		95.54
Natural gas ($ per MCF)			4.58			3.92

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of March 31, 2023, Alaska contributed 16 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

Net Income

Earnings from Alaska decreased $168 million in the first quarter of 2023. Decreases to earnings include:

• Lower realized crude oil prices.

• Lower sales volumes.

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

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

Production

Average production decreased 2 MBOED in the first quarter of 2023. 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.

Exploration Activity

In the first quarter of 2023, we drilled the Bear-1 exploration well which was determined to be a dry hole, increasing exploration expenses by approximately $34 million before-tax. The well, located south of the Kuparuk River Unit and east of the Colville River on state lands, is in an area that we are continuing to evaluate.

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Results of Operations			Table of Contents

Lower 48

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	1,852		2,790
Average Net Production
Crude oil (MBD)			561			538
Natural gas liquids (MBD)			239			191
Natural gas (MMCFD)			1,418			1,426
Total Production (MBOED)			1,036			967
Average Sales Prices
Crude oil ($ per bbl)			$	74.36		93.55
Natural gas liquids ($ per bbl)			24.58			40.42
Natural gas ($ per MCF)			2.92			4.63

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties in the Gulf of Mexico. As of March 31, 2023, the Lower 48 contributed 63 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

Net Income

Earnings from the Lower 48 decreased $938 million in the first quarter of 2023. 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 at year-end 2022.

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

Offsets to the earnings decrease include:

• Higher sales volumes.

• Improved commercial performance and timing.

Production

Average production increased 69 MBOED in the first quarter of 2023. Increases to production include:

• New wells online from our development programs in the Delaware Basin, Eagle Ford, Midland Basin and Bakken.

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

Offsets to the production increases include:

• Normal field decline.

• Downtime related to third-party high line pressure and compressor maintenance in the Permian.

• Divestiture of noncore assets.

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Results of Operations			Table of Contents

Canada

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	6		291
Average Net Production
Crude oil (MBD)			6			6
Natural gas liquids (MBD)			3			3
Bitumen (MBD)			69			67
Natural gas (MMCFD)			64			63
Total Production (MBOED)			89			86
Average Sales Prices
Crude oil ($ per bbl)			$	65.07		82.13
Natural gas liquids ($ per bbl)			29.02			41.83
Bitumen ($ per bbl)			29.49			65.86
Natural gas ($ per MCF)			4.64			3.25

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 March 31, 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 $285 million in the first quarter of 2023. 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 in our Canada segment ended in the second quarter of 2022.

Production

Average production increased 3 MBOED in the first quarter of 2023. Increases to production include:

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

Offsets to the production increases include:

• Downtime associated with a third-party pipeline outage.

• Normal field decline.

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Europe, Middle East and North Africa

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	365		412
Consolidated Operations
Average Net Production
Crude oil (MBD)			117			113
Natural gas liquids (MBD)			4			4
Natural gas (MMCFD)			342			331
Total Production (MBOED)			178			172
Average Sales Prices
Crude oil ($ per bbl)			$	83.52		94.68
Natural gas liquids ($ per bbl)			47.91			58.67
Natural gas ($ per MCF)			17.18			29.18

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

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea and the Norwegian Sea, Qatar, Libya and commercial and terminalling operations in the U.K. As of March 31, 2023, our Europe, Middle East and North Africa operations contributed 10 percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.

Net Income

Earnings from Europe, Middle East and North Africa decreased by $47 million in the first quarter of 2023. Decreases to earnings include:

• Lower realized commodity prices.

• Lower crude and NGL sales volumes driven by the timing of crude lifts.

Offsets to the earnings decreases were foreign exchange gains as the USD strengthened against the Norwegian Kroner.

Consolidated Production

Average consolidated production increased 6 MBOED in the first quarter of 2023. Increases to production include:

• 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 performance in Norway.

Offsets to the production increases include normal field decline.

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Results of Operations			Table of Contents

Asia Pacific

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	522		1,136
Consolidated Operations
Average Net Production
Crude oil (MBD)			63			64
Natural gas (MMCFD)			56			271
Total Production (MBOED)			72			109
Average Sales Prices
Crude oil ($ per bbl)			$	83.50		104.84
Natural gas ($ per MCF)			4.30			7.01

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

The Asia Pacific segment has operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. As of March 31, 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 $614 million in the first quarter of 2023. Decreases to earnings include:

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

• Lower realized commodity prices.

• Lower sales volumes primarily driven by the divestiture of our Indonesia assets in the first quarter of 2022.

Consolidated Production

Average consolidated production decreased 37 MBOED in the first quarter of 2023. Decreases to production include:

• Divestiture of our Indonesia assets in the first quarter of 2022.

• 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.

Planned Acquisition

In March, 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 (APLNG). Both EIG's transaction with Origin Energy and our shareholder acquisition are subject to Australian regulatory approvals and other customary closing conditions.

Exploration

In October 2022, we entered into a JOA with 3D Oil for 80 percent interest in Exploration Permit (VIC/P79) in the Otway Basin, Australia. In March 2023, we received regulatory approvals on the title transfer and made a $3 million farm-in payment to 3D Oil.

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Other International

			Three Months Ended March 31
			2023			2022
Net Income ($MM)			$	1		—

The Other International segment consists of interests in Colombia as well as contingencies associated with prior operations in other countries.

Corporate and Other

			Millions of Dollars
			Three Months Ended March 31
			2023			2022
Net Income (Loss)
Net interest expense			$	(90)		(218)
Corporate general and administrative expenses			(90)			(79)
Technology			6			58
Other income (expense)			(68)			785
			$	(242)		546

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense improved by $128 million in the first quarter of 2023, primarily due to higher interest income as well as lower interest expenses as a result of our 2022 debt reduction transactions.

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

Technology includes our investment in low-carbon technologies as well as other new technologies or businesses and licensing revenues. Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery, as well as LNG. See Note 15. Earnings from Technology decreased $52 million in the first quarter 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 first quarter of 2023, “Other” decreased $853 million primarily due to 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. These 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 4 and Note 18*.*

Port Arthur LNG Acquisition

In March, we acquired a 30 percent direct equity holding in PALNG, a joint venture for the development of Phase 1 of the Port Arthur LNG project. In addition we entered into a 20-year agreement to purchase 5 MTPA of LNG offtake at the start of Phase 1 and a natural gas supply management agreement, whereby we will manage the feedgas supply requirements for Phase 1. See Note 3.

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Capital Resources and Liquidity			Table of Contents

Capital Resources and Liquidity

Financial Indicators

			Millions of Dollars
			March 31 2023			December 31 2022
Cash and cash equivalents			$	6,974		6,458
Short-term investments			1,635			2,785
Total debt			16,583			16,643
Total equity			47,783			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 three months of 2023, the primary uses of our available cash were $2.9 billion to support our ongoing capital expenditures and investments program, $1.7 billion to repurchase common stock, and $1.5 billion to pay the ordinary dividend and VROC.

At March 31, 2023, we had total liquidity of $14.1 billion, comprised of cash and cash equivalents of $7.0 billion, short-term investments of $1.6 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 $5.4 billion for the first three months of 2023, compared with $5.1 billion for the corresponding period of 2022. The increase is primarily due to the absence of Libya foreign tax and royalty payments made in the first quarter of 2022 related to prior years and higher produced sales volumes in the Lower 48, partially offset by lower realized commodity prices across all products.

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

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

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

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Investing Activities

For the first three months of 2023, we invested $2.9 billion in capital expenditures and investments. Our 2023 operating plan capital expenditures are currently expected to be between $10.7 billion to $11.3 billion. Our 2022 capital expenditures and investments were $10.2 billion. See the “Capital Expenditures and Investments” section.

In March 2023, we invested $0.4 billion in the PALNG joint venture, that will participate in Phase 1 of the Port Arthur LNG project. See Note 3.

Proceeds from asset sales were $0.2 billion in the first three months of 2023 compared with $2.3 billion for the corresponding period in 2022. In the first quarter of 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of CVE and proceeds of $0.8 billion primarily from the sale of our Indonesia assets. See Note 4.

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 three months of 2023 included net sales of $1,065 million of investments. We had net sales of $1,244 million of short-term instruments and net purchases of $179 million of long-term instruments*.* See Note 12.

Financing Activities

We have a revolving credit facility totaling $5.5 billion with an expiration date of February 2027. The credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to $5.5 billion in available borrowing capacity under our revolving credit facility at March 31, 2023.

Our debt balance at March 31, 2023 was $16.6 billion compared with $16.6 billion at December 31, 2022. In 2021, we announced a debt target reduction of $5 billion by 2026. Since that announcement, we have reduced debt by $3.3 billion. The current portion of debt, including payments for finance leases, is $1,317 million. Payments are expected to be made using current cash balances and cash generated by operating activities.

In March 2023, Moody's affirmed our long-term credit rating shown below.

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

• Fitch: “A” with a “stable” outlook

• S&P: “A-” with a “stable” outlook

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

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

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2023 and December 31, 2022, we had direct bank letters of credit of $329 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.

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Capital Requirements

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

We believe in delivering value to our shareholders through our 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 three months of 2023, we paid ordinary dividends of $0.51 cents per common share and a VROC payment of $0.70 cents per common share. In the first three months of 2022, we paid ordinary dividends of $0.46 cents per common share and a VROC payment of $0.20 cents per common share.

In May 2023, we declared an ordinary dividend of $0.51 cents per share and a VROC dividend of $0.60 cents per share. The ordinary dividend of $0.51 cents per share is payable June 1, 2023, to shareholders of record on May 16, 2023. The VROC of $0.60 cents per share is payable July 14, 2023, to shareholders of record on June 27, 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 March 31, 2023, share repurchases since the inception of our current program totaled 350.2 million shares and $25.1 billion. In the three months ended March 31, 2023, we repurchased 15.4 million shares for a cost of $1.7 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.

Capital Expenditures and Investments

			Millions of Dollars
			Three Months Ended March 31
			2023			2022
Alaska			$	406		253
Lower 48			1,704			1,062
Canada			136			122
Europe, Middle East and North Africa			209			172
Asia Pacific			63			1,538
Other International			—			—
Corporate and Other			379			14
Capital expenditures and investments			$	2,897		3,161

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

• Development activities in the Lower 48, primarily in the Permian, Eagle Ford and Bakken.

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

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

• Development and exploration activities across assets in Norway.

• Continued development activities in Malaysia and China.

• Capital associated with our investment in PALNG.

Our 2023 operating plan capital expenditure guidance is currently expected to be $10.7 billion to $11.3 billion. 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
			Three Months Ended March 31, 2023
Revenues and Other Income			$	10,066
Income before income taxes*			3,015
Net Income			2,920

*Includes approximately $1.8 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

			Millions of Dollars
			March 31, 2023			December 31, 2022
Current assets			$	7,257		10,766
Amounts due from Non-Obligated Subsidiaries, current			1,554			1,892
Noncurrent assets			83,132			79,269
Amounts due from Non-Obligated Subsidiaries, noncurrent			7,193			6,552
Current liabilities			6,816			8,201
Amounts due to Non-Obligated Subsidiaries, current			2,786			3,248
Noncurrent liabilities			42,347			40,389
Amounts due to Non-Obligated Subsidiaries, noncurrent			27,359			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 8.

Legal and Tax Matters

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

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

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 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 March 31, 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 $182 million at both March 31, 2023 and 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 8 for information on environmental litigation.

Climate Change

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws 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 and is also aligned with our Triple Mandate to responsibly meet energy transition pathway demand, deliver competitive returns on and of capital and achieve our net-zero operational emissions ambition.

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

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

◦Focus on capital discipline by using 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 that could address end-use emissions.

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

• Contribute to the energy transition:

◦Build 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.

In April, we announced that we are accelerating our operational GHG emissions intensity reduction target through 2030. We are now targeting a reduction in gross operated and net equity operational emissions intensity of 50-60 percent from 2016 levels by 2030, an improvement from the previously announced target of 40-50 percent. In addition, we continue to evaluate low-carbon options in Hydrogen and CCS that align with our disciplined investment criteria.

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 8 for information on climate change litigation.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, 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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