cop-20231231

2023

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the transition period from _______________ to _______________

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)


Delaware			01-0562944
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer identification No.)

925 N. Eldridge Parkway, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading symbols	Name of each exchange on which registered
Common Stock, $.01 Par Value	COP	New York Stock Exchange
7% Debentures due 2029	CUSIP—718507BK1	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by checkmark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $103.61, was $124.0 billion.

The registrant had 1,176,408,368 shares of common stock outstanding at January 31, 2024.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2024 (Part III)

Table of Contents


		Page
Commonly Used Abbreviations		1

Item
	Part I

1 and 2.	Business and Properties	2
	Corporate Structure	2
	Segment and Geographic Information	2
	Alaska	4
	Lower 48	6
	Canada	7
	Europe, Middle East and North Africa	8
	Asia Pacific	11
	Other International	13
	Other	14
	Delivery Commitments	15
	Competition	15
	Human Capital Management	16
	General	19
1A.	Risk Factors	20
1B.	Unresolved Staff Comments	28
1C.	CyberSecurity	28
3.	Legal Proceedings	30
4.	Mine Safety Disclosures	30
	Information About our Executive Officers	30

	Part II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
6.	[Reserved]
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

7A.	Quantitative and Qualitative Disclosures About Market Risk	67
8.	Financial Statements and Supplementary Data	70
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	160
9A.	Controls and Procedures	160
9B.	Other Information	160
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	160

	Part III

10.	Directors, Executive Officers and Corporate Governance	161
11.	Executive Compensation	161
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	161
13.	Certain Relationships and Related Transactions, and Director Independence	161
14.	Principal Accounting Fees and Services	161

	Part IV

15.	Exhibits, Financial Statement Schedules	162
	Signatures	167


Commonly Used Abbreviations			Table of Contents

Commonly Used Abbreviations

The following industry-specific, accounting and other terms and abbreviations may be commonly used in this report.


Currencies		Accounting
$ or USD	U.S. dollar	ARO	asset retirement obligation
CAD	Canadian dollar	ASC	accounting standards codification
EUR	Euro	ASU	accounting standards update
GBP	British pound	DD&A	depreciation, depletion and
NOK	Norwegian kroner		amortization
		FASB	Financial Accounting Standards
Units of Measurement			Board
BBL	barrel	FIFO	first-in, first-out
BCF	billion cubic feet	G&A	general and administrative
BOE	barrels of oil equivalent	GAAP	generally accepted accounting
MBD	thousands of barrels per day		principles
MCF	thousand cubic feet	LIFO	last-in, first-out
MM	million	NPNS	normal purchase normal sale
MMBOE	million barrels of oil equivalent	PP&E	properties, plants and equipment
MBOED	thousand of barrels of oil	VIE	variable interest entity
	equivalent per day
MMBOED	million of barrels of oil	Miscellaneous
	equivalent per day	CERCLA	Federal Comprehensive
MMBTU	million British thermal units		Environmental Response
MMCFD	million cubic feet per day		Compensation and Liability Act
MTPA	million tonnes per annum	DEI	diversity, equity and inclusion
		EPA	Environmental Protection Agency
Industry		ESG	environmental, social and governance
BLM	Bureau of Land Management	EU	European Union
CBM	coalbed methane	FERC	Federal Energy Regulatory
CCS	carbon capture and storage		Commission
E&P	exploration and production	GHG	greenhouse gas
FEED	front-end engineering and design	HSE	health, safety and environment
FID	final investment decision	ICC	International Chamber of Commerce
FPS	floating production system	ICSID	World Bank’s International
FPSO	floating production, storage and		Centre for Settlement of
	offloading		Investment Disputes
G&G	geological and geophysical	IRS	Internal Revenue Service
JOA	joint operating agreement	OTC	over-the-counter
LNG	liquefied natural gas	NYSE	New York Stock Exchange
NGLs	natural gas liquids	SEC	U.S. Securities and Exchange
OPEC	Organization of Petroleum		Commission
	Exporting Countries	TSR	total shareholder return
PSC	production sharing contract	U.K.	United Kingdom
PUDs	proved undeveloped reserves	U.S.	United States of America
SAGD	steam-assisted gravity drainage	VROC	variable return of cash
WCS	Western Canadian Select
WTI	West Texas Intermediate


1			ConocoPhillips 2023 10-K


Business and Properties			Table of Contents

Part I

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and Properties, contain forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any 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 headings “Risk Factors” beginning on page 20 and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 65.

Items 1 and 2. Business and Properties

Corporate Structure

ConocoPhillips is an independent E&P company headquartered in Houston, Texas with operations and activities in 13 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; LNG developments; oil sands in Canada; and an inventory of global exploration prospects. On December 31, 2023, we employed approximately 9,900 people worldwide and had total assets of about $96 billion. Total company production for the year was 1,826 MBOED.

ConocoPhillips was incorporated in the state of Delaware in 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002. In April 2012, ConocoPhillips completed the separation of the downstream business into an independent, publicly traded energy company, Phillips 66.

Segment and Geographic Information

We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. For operating segment and geographic information, see Note 24.


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Business and Properties			Table of Contents

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

The information listed below appears in the “Supplementary Data - Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

•Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.

•Net production of crude oil, NGLs, natural gas and bitumen.

•Average sales prices of crude oil, NGLs, natural gas and bitumen.

•Average production costs per BOE.

•Net wells completed, wells in progress and productive wells.

•Developed and undeveloped acreage.

The following table is a summary of the proved reserves information included in the “Supplementary Data - Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 85 percent of our proved reserves are in countries that belong to the Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six MCF of natural gas converts to one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the following summary reserves table.


	Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31	2023	2022	2021
Crude oil
Consolidated operations	3,032	2,975	2,964
Equity affiliates	89	93	63
Total Crude Oil	3,121	3,068	3,027

Natural gas liquids
Consolidated operations	892	845	644
Equity affiliates	48	50	33
Total Natural Gas Liquids	940	895	677

Natural gas
Consolidated operations	1,408	1,461	1,523
Equity affiliates	879	959	617
Total Natural Gas	2,287	2,420	2,140

Bitumen
Consolidated operations	410	216	257
Total Bitumen	410	216	257

Total consolidated operations	5,742	5,497	5,388
Total equity affiliates	1,016	1,102	713
Total company	6,758	6,599	6,101


3			ConocoPhillips 2023 10-K


Business and Properties			Table of Contents

Alaska

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs. We are the largest crude oil producer in Alaska and have major ownership interests in two of North America’s largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. Additionally, we are one of Alaska’s largest owners of state, federal and fee exploration leases, with approximately one million net undeveloped acres at year-end 2023. Alaska operations contributed 15 percent of our consolidated liquids production and two percent of our consolidated natural gas production.


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Greater Prudhoe Area	36.1	%	Hilcorp	66	16	35	87
Greater Kuparuk Area	89.2-94.7		ConocoPhillips	64	—	2	65
Western North Slope	100.0		ConocoPhillips	43	—	1	43
Total Alaska				173	16	38	195

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Unit, which consists of the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest conventional oil field in North America, is the site of a large waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation. Field installations include seven production facilities, two gas plants, two seawater plants and a central power station. In 2023, on average, there were two rigs drilling throughout the year.

Greater Kuparuk Area

The Greater Kuparuk Area includes the Kuparuk River Unit, which consists of the Kuparuk Field and six satellite fields. Field installations include three central production facilities which separate oil, natural gas and water, and a seawater treatment plant. In 2023, we operated one drilling rig and two workover rigs. The Nuna project, which targets the Moraine reservoir, was sanctioned in 2023 with first oil anticipated by early 2025. The Coyote reservoir discovered in 2021 progressed to development in 2023 with additional wells planned in 2024 and 2025.


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Business and Properties			Table of Contents

Western North Slope

The Western North Slope includes the Colville River Unit, the Greater Mooses Tooth Unit and the Bear Tooth Unit. In 2023, on average, there were two rigs drilling throughout the year.

The Colville River Unit includes the Alpine Field and four satellite fields. Field installations include one central production facility, which separates oil, natural gas and water. In 2023, we focused our development activities on the Narwhal trend, a reservoir within the Alpine Field, and anticipate completing the current phase in 2024. The results will help inform the design and optimization of future development.

The Greater Mooses Tooth Unit is the first unit established entirely within the National Petroleum Reserve Alaska (NPR-A). The unit was constructed in two phases: Greater Mooses Tooth #1 (GMT1) and Greater Mooses Tooth #2 (GMT2). Development activity continued in 2023.

On March 12, 2023, the Department of the Interior issued a Record of Decision (ROD) approving the Willow project, and in December 2023, we announced FID. The project will consist of three drill sites, an operations center and camp, and a processing facility. First production is anticipated in 2029.

Exploration

In 2023, the Bear-1 exploration well was drilled at a location 30 miles south of the Greater Kuparuk Area and east of the Colville River on state lands. No commercial hydrocarbons were found, and the well was deemed a dry hole and permanently plugged and abandoned.

Transportation

We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile pipeline that is part of Trans-Alaska Pipeline System (TAPS). We have a 29.5 percent ownership interest in TAPS, and we also have ownership interests in and operate the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope production, using five company-owned, double-hulled tankers, and charters third-party vessels, as necessary. The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.


5			ConocoPhillips 2023 10-K


Business and Properties			Table of Contents

Lower 48

The Lower 48 segment consists of operations located in the 48 contiguous U.S. states and the Gulf of Mexico, with a portfolio mainly consisting of low cost of supply, short cycle time, resource-rich unconventional plays and commercial operations. Based on 2023 production volumes, the Lower 48 is our largest segment and contributed 64 percent of our consolidated liquids production and 76 percent of our consolidated natural gas production.


	2023
	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Delaware Basin	274	135	768	537
Eagle Ford	114	61	306	226
Midland Basin	105	42	205	182
Bakken	66	16	150	106
Other	10	2	28	16
Total Lower 48	569	256	1,457	1,067

Delaware Basin

We hold approximately 654,000 unconventional net acres in the Delaware Basin spanning west Texas through southeast New Mexico. Current development activity targets prospects in the Avalon, Bone Springs and Wolfcamp formations while balancing leasehold obligations and permit terms. We operated ten rigs and three frac crews on average during 2023, resulting in 160 operated wells drilled and 148 operated wells brought online.

Eagle Ford

We hold approximately 199,000 unconventional net acres in the Eagle Ford located in south Texas. The current focus is on full-field development, using customized well spacing and stacking patterns adapted through reservoir analysis. We operated six rigs and two frac crews on average during 2023, resulting in 143 operated wells drilled and 123 operated wells brought online.

Midland Basin

We hold approximately 248,000 unconventional net acres in the Midland Basin located in west Texas. The current development strategy is focused on full-field development utilizing multi-well pad projects targeting both Spraberry and Wolfcamp reservoir targets. We operated five rigs and two frac crews on average during 2023, resulting in 98 operated wells drilled and 106 operated wells brought online.

Bakken

We hold approximately 562,000 unconventional net acres in the Williston Basin located in North Dakota and eastern Montana. The primary producing zones are the Middle Bakken and Three Forks formations. We operated three rigs and one frac crew on average during 2023, resulting in 61 operated wells drilled and 37 operated wells brought online.

Partner-Operated

We participate in partner-operated wells when they align with our investment decision criteria and development strategies. In 2023, we participated in partner-operated wells with varying working interests across our Lower 48 portfolio.

Facilities

We operate and own, with varying interests, centralized condensate processing facilities in Texas and New Mexico in support of our Eagle Ford, Delaware and Midland assets.


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Business and Properties			Table of Contents

Canada

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


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Bitumen MBD	Total MBOED
Average Daily Net Production
Surmont*	100.0	%	ConocoPhillips	—	—	—	81	81
Montney	100.0		ConocoPhillips	9	3	65	—	23
Total Canada				9	3	65	81	104
*Acquired remaining 50 percent working interest in Surmont in October 2023. See Note 3.

Our bitumen resources in Canada are produced via SAGD, an enhanced thermal oil recovery method where steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing. Operations include two central processing facilities for treatment and blending of bitumen, and a diluent recovery unit. These facilities have allowed the asset to lower blend ratio and diluent supply costs, while gaining protection from diluent supply disruptions and increased market access for our product. At December 31, 2023, we held approximately 684,000 net acres of land in the Athabasca Region of northeastern Alberta.

Surmont

The Surmont oil sands leases are located south of Fort McMurray, Alberta. Surmont is a 100 percent working interest asset that offers sustained, long-life production. We are focused on keeping facilities full, structurally lowering costs, reducing GHG intensity and optimizing asset performance.

In October 2023, we completed our acquisition of the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd. We achieved first production on Pad 267 in December. We expect first production in 2025 on our next pad, Pad 104.

Montney

The Montney is an unconventional play located in northeastern British Columbia. At December 31, 2023, we held approximately 297,000 net acres of land in the Montney.

In 2023, we continued development of the asset with the next series of pads, which included drilling 16 horizontal wells and bringing 15 wells online. The second phase of our central processing facility was successfully started in the third quarter.


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Business and Properties			Table of Contents

Europe, Middle East and North Africa

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, and commercial and terminalling operations in the U.K. In 2023, operations in Europe, Middle East and North Africa contributed nine percent of our consolidated liquids production and 16 percent of our consolidated natural gas production.

Norway


			2023
	Interest	Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Greater Ekofisk Area	28.3-35.1%	ConocoPhillips	42	2	42	51
Heidrun	24.0	Equinor	10	—	39	17
Aasta Hansteen	10.0	Equinor	—	—	66	11
Troll	1.6	Equinor	1	—	59	11
Visund	9.1	Equinor	1	2	48	11
Alvheim	20.0	Aker BP	5	—	10	7
Other	Various	Equinor	5	—	15	7
Total Norway			64	4	279	115

Greater Ekofisk Area

The Greater Ekofisk Area is located offshore Stavanger, Norway, in the North Sea, and is comprised of five producing fields. Crude oil is exported to our operated terminal located at Teesside, U.K., and the natural gas is exported to Emden, Germany. The Tommeliten A development, a new subsea tieback to Ekofisk, achieved first production in 2023, and the Eldfisk North subsea development will be tied back to Eldfisk, with first production expected in 2024.

Heidrun Field

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and exported via shuttle tankers. Most of the gas is transported to Europe via gas processing terminals in Norway with some reinjected for pressure support if required. A portion of the gas is also transported for use as feedstock in a methanol plant in Norway, in which we have an 18 percent interest.

Aasta Hansteen Field

The Aasta Hansteen Field is located in the Norwegian Sea. Produced condensate is loaded onto shuttle tankers and transported to market. Gas is transported through the Polarled gas pipeline to the onshore Nyhamna processing plant for final processing prior to export to market.

Troll Field

The Troll Field lies in the northern part of the North Sea and consists of the Troll A, B and C platforms. The natural gas from Troll A is transported to Kollsnes, Norway. Crude oil from floating platforms Troll B and Troll C is transported to Mongstad, Norway, for storage and export.


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Business and Properties			Table of Contents

Visund Field

The Visund Field is located in the northern part of the North Sea and consists of a floating drilling, production and processing unit and subsea installations. Crude oil is transported by pipeline to a nearby third-party field for storage and export via tankers. The natural gas is transported to the gas processing plants at Kollsnes and Kårstø, through the Gassled transportation system.

Alvheim Field

The Alvheim Field is located in the northern part of the North Sea and consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers and natural gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, U.K., through the SAGE Pipeline. The Kobra East and Gekko (KEG) project, a new subsea tieback to the Alvheim FPSO, achieved first production in 2023.

Other Fields

We also have varying ownership interests in three other producing fields in the Norwegian sector of the North Sea. In 2023, the partner-operated Breidablikk project achieved first production.

Exploration

In 2023, we participated in the partner-operated Ve exploration well on PL919 located in the North Sea. We were also awarded two new exploration licenses, PL1146B and PL036G located in the North Sea and traded into two licenses, PL886 and PL886B located in the Norwegian Sea. In the third quarter of 2023, we recorded the investment in the suspended Warka discovery well on license PL1009, located in the Norwegian Sea and drilled in 2020, as dry hole expense. In 2024, we plan to drill the second appraisal well in the 2020 Slagugle discovery located in the Norwegian Sea and participate in a partner-operated exploration well in the Alvheim Deep prospect.

Transportation

We have a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and NGLs processing facility in Teesside, U.K.

Facilities

We operate and have a 40.25 percent ownership interest in a crude oil stabilization and NGLs processing facility at Teesside, U.K. to support our Norway operations.


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Business and Properties			Table of Contents

Qatar


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
QatarEnergy LNG N(3)	30.0	%	QatarEnergy LNG	13	8	375	83

QatarEnergy LNG N(3) (N3), formerly Qatar Liquefied Gas Company Limited (3) (QG3), is an integrated development jointly owned by QatarEnergy (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). N3 consists of upstream natural gas production facilities, which produce approximately 1.4 gross BCF per day of natural gas from Qatar’s North Field over a 25-year life, in addition to a 7.8 million gross tonnes per year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally.

N3 executed the development of the onshore and offshore assets as a single integrated development with QatarEnergy LNG N(4) (N4), formerly Qatargas 4 (QG4), a joint venture between QatarEnergy and Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the N3 and N4 joint ventures. Production from the LNG trains and associated facilities is combined and shared.

During 2022, we were awarded a 25 percent interest in each of two new joint ventures with QatarEnergy to participate in the North Field East (NFE) and North Field South (NFS) LNG projects. Formation of the NFE joint venture, QatarEnergy LNG NFE (4) (NFE4), formerly Qatar Liquefied Gas Company Limited (8) (QG8), closed in December 2022 and the formation of the NFS joint venture, QatarEnergy LNG NFS (3) (NFS3), formerly Qatar Liquefied Gas Company Limited (12) (QG12), closed in June 2023. See Note 3 and Note 4.

Libya


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Waha Concession	20.4	%	Waha Oil Co.	48	—	29	53

The Waha Concession is made up of multiple concessions and encompasses approximately 13 million acres onshore in the Sirte Basin for exploration and production activity. Oil is transported by pipeline to the Es Sider terminal for export. Natural gas is transported and sold domestically. Current production comes from 13 existing fields within the Waha Concession.


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Business and Properties			Table of Contents

Asia Pacific

The Asia Pacific segment has exploration and production operations in China, Malaysia, Australia and commercial operations in China, Singapore and Japan. In 2023, operations in the Asia Pacific segment contributed five percent of our consolidated liquids production and three percent of our consolidated natural gas production.

Australia


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Australia Pacific LNG	47.5	%	ConocoPhillips/Origin Energy	—	—	844	141

Australia Pacific LNG Pty Ltd. (APLNG), our joint venture with Origin Energy Limited and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for export. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.

We operate two fully subscribed 4.5 MTPA LNG trains. Approximately 3,500 net wells are ultimately expected to supply both the LNG sales contracts and domestic gas market. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities and an export pipeline connecting the gas fields to the LNG facilities. The LNG is being sold to Sinopec under 20-year sales agreements for 7.6 MTPA of LNG, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately 1 MTPA of LNG.

For additional information, see Note 3, Note 4 and Note 10.

Exploration

We own an 80 percent working interest in both Exploration Permit (T/49P) and (VIC/P79) located in the Otway Basin, Australia. Existing seismic data for both permits is being evaluated for future exploration drilling opportunities.

During 2023, we executed a drilling consortium agreement with other operators in Australia and secured a contract for a semi-sub drilling rig. The proposed exploration program involves seabed surveys and two exploration wells planned for 2025.


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Business and Properties			Table of Contents

China


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Penglai	49.0	%	CNOOC	32	—	—	32

Penglai

The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are being developed in stages from large offshore platforms and a FPSO. Most crude oil produced from the block is sold to the China domestic market, with the remainder exported to international markets.

Phase 3 consists of three wellhead platforms and a central processing platform. First production from Phase 3 was achieved in 2018. This project could include up to 186 wells, 175 of which have been completed and brought online as of December 2023.

Phase 4A consists of one wellhead platform and achieved first production in 2020. This project could include up to 62 new wells, 54 of which have been completed and brought online as of December 2023.

Phase 4B consists of two wellhead platforms, WHP-H and WHP-N, both of which achieved first production in the fourth quarter of 2023. This project could include up to 144 new wells, 3 of which have been completed and brought online as of December 2023.

Malaysia


				2023
	Interest		Operator	Crude Oil MBD	NGL MBD	Natural Gas MMCFD	Total MBOED
Average Daily Net Production
Gumusut	29.5	%	Shell	13	—	—	13
Malikai	35.0		Shell	12	—	—	12
Kebabangan (KBB)	30.0		KPOC	1	—	47	9
Siakap North-Petai	21.0		PTTEP	2	—	1	2
Total Malaysia				28	—	48	36

We have varying stages of exploration, development and production activities across approximately 2.7 million net acres in Malaysia, with working interests in six PSCs. Four of these PSCs are located in waters off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC), which we do not operate, and Block SB405, an operated exploration block acquired in 2021. We also operate another two exploration blocks, Block WL4-00 and Block SK304, in waters off the eastern Malaysian state of Sarawak.

Block J

Gumusut

We own a 29.5 percent working interest in the unitized Gumusut Field. Gumusut Phase 3 first oil was achieved in 2022. Development drilling associated with Gumusut Phase 4, a four-well program targeting the Brunei acreage of the unitized Gumusut Field that straddles Malaysia and Brunei waters, is planned to commence in early 2024 with first oil anticipated in early 2025. The unitized Gumusut Field is operated on a FPS with oil evacuation via a pipeline to the Sabah Oil and Gas Terminal (SOGT) for tanker liftings.


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KBBC

We own a 30 percent working interest in the KBB, Kamunsu East and Kamunsu East Upthrown Canyon gas and condensate fields.

KBB

Gas is transported from the KBB platform via pipeline for sale to the domestic gas market. During 2019, KBB tied-in to a nearby third-party floating LNG vessel, which provided increased gas offtake capacity.

Block G

Malikai

We own a 35 percent working interest in Malikai. Malikai Phase 2 development first oil was achieved in February 2021. Malikai operates on a tension leg platform and pipes oil to the KBB platform for processing. Oil evacuation is via pipeline to SOGT for tanker liftings.

Siakap North-Petai

We own a 21 percent working interest in the unitized Siakap North-Petai (SNP) oil field. First oil from SNP Phase 2 was achieved in November 2021. The subsea system in the SNP oil field is tied back to a FPSO operated by PTTEP.

Exploration

We own a 50 percent working interest and operate both Blocks WL4-00 and SK304. Block WL4-00 encompasses 0.3 million net acres primarily in the Salam and Benum Fields. Block SK304 encompasses 1.1 million net acres off the coast of Sarawak, offshore Malaysia. We continue to evaluate these blocks and are using information from prior well results to help optimize future development plans.

In 2021, we were awarded operatorship and an 85 percent working interest in Block SB405 encompassing 1.2 million net acres off the coast of Sabah, offshore Malaysia. A 3D seismic survey was acquired in 2022, and processing and evaluation of this data is currently ongoing.

Other International

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

Colombia

We have an 80 percent operating interest in the Middle Magdalena Basin Block VMM-3 extending over approximately 67,000 net acres. In addition, we have an 80 percent working interest in the VMM-2 Block, which extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block. The contracts for this project are currently in force majeure due to the lack of a defined environmental licensing required for the execution of unconventional exploratory activities. Additionally, the government of Colombia supports a ban on such activities.

Venezuela

For discussion of our contingencies in Venezuela, see Note 11.


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Other

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which includes natural gas, crude oil, bitumen, NGLs, LNG and power. Marketing activities are performed through offices in the U.S., Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase and sell third-party commodity volumes to better position the company to satisfy customer demand while fully utilizing transportation and storage capacity.

Crude Oil, Bitumen and NGLs

Our crude oil, bitumen and NGL revenues are derived from production in the U.S., Canada, Asia, Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Natural Gas

Our natural gas production, along with third-party purchased gas, is primarily marketed in the U.S., Canada and Europe. Our natural gas is sold to a diverse client portfolio, which includes local distribution companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and interruptible transportation agreements to major market hubs.

LNG

We have producing equity LNG facilities located in Australia and Qatar, by which volumes are primarily sold under long-term contracts with prices based on market indices. In 2023, we continued to progress our global LNG strategy, acquiring a 30 percent equity interest in the Port Arthur LNG (PALNG) facility and contracting 5 MTPA offtake capacity. We secured additional offtake capacity in North America of 2.4 MTPA, which includes a 20-year offtake agreement for approximately 2.2 MTPA at the Saguaro LNG project on the West Coast of Mexico, subject to Mexico Pacific reaching FID and other certain conditions precedent as well as a 5-year offtake agreement for 0.2 MTPA at the Energia Costa Azul Phase 1. In addition, we executed additional regasification capacity and services agreements for approximately 1.7 MTPA, including a 15-year throughput agreement for 1.5 MTPA of capacity and a 5-year services agreement for 0.2 MTPA at the Gate LNG terminal in the Netherlands. Our marketing efforts are focused on further progressing the placement of our offtake volumes into Europe and Asia.

Energy Response Partnerships

We maintain memberships in several response and containment partnerships across the globe as a key element of our emergency response preparedness program in addition to internal response resources.

Marine Well Containment Company (MWCC)

We are a founding member of the MWCC, a non-profit organization formed in 2010, which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC’s containment system meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico.

Oil Spill Response Limited (OSRL) - Subsea Well Intervention Service (SWIS)

OSRL-SWIS is a non-profit organization in the U.K. that is an industry funded joint initiative providing the capability to respond to subsea well-control incidents. Through our SWIS subscription, ConocoPhillips has access to equipment that is maintained and stored in a response ready state. This provides well capping and containment capability outside the U.S.

Oil Spill Response Removal Organizations (OSROs)

We maintain memberships in several OSROs, many of which are not-for-profit cooperatives owned by the member companies wherein we may actively participate as a member of the board of directors, steering committee, work group or other supporting role. In North America, our primary OSROs include the Marine Spill Response Corporation for the continental U.S. and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince William Sound, respectively. Internationally, we maintain memberships in various OSROs including Oil Spill Response Limited, the Norwegian Clean Seas Association for Operating Companies, Australian Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.


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Technology

We have several technology programs that improve our ability to develop unconventional reservoirs, increase recoveries from our legacy fields, improve the efficiency of our exploration program, produce heavy oil economically with lower emissions and implement sustainability measures.

LNG Liquefaction

We are the second-largest LNG liquefaction technology provider globally. Our Optimized Cascade® LNG liquefaction technology has been licensed for use in 28 LNG trains around the world, with FEED studies ongoing for additional trains.

Low-Carbon Technologies

In 2021, we established a multi-disciplinary Low-Carbon Technologies organization, with the remit to support our net-zero ambition, understand the alternative energy landscape and prioritize opportunities for future competitive investment. We continue our focus on implementing emissions reduction projects across our global portfolio, including operational efficiency measures and methane and flaring reductions. In April 2023, we accelerated our 2030 GHG emissions intensity reduction target to a 50-60 percent reduction by 2030 from a 2016 baseline on both a gross operated and net equity basis. In addition, we set a new near-zero methane intensity target of less than 1.5-kilogram carbon dioxide equivalent per BOE by 2030. We are also on track to meet the World Bank Zero Routine Flaring goal by 2025. To help achieve these targets, the Low-Carbon Technologies organization continued to work with the company's business units to develop and implement region-specific emission reduction initiatives and identify potential technology solutions for hard-to-abate emissions.

Over the last two years, we continued our work to identify additional pathways to abate our Scope 1 and 2 emissions as well as low-carbon opportunities for future competitive investment. For example:

•We conducted CCS and electrification studies, initiated zero/low emission equipment design enhancements, installed mechanisms to continuously monitor and detect methane emissions and implemented operational changes to reduce flaring and methane venting volumes.

•We evaluated carbon dioxide storage sites primarily along the U.S. Gulf Coast, progressed land acquisition efforts and business development work, initiated permitting activities for potential appraisal wells for carbon sequestration and advanced engineering studies for multiple opportunities.

•We advanced hydrogen opportunities in the U.S., Middle East and Asia Pacific regions. In September 2023, JERA and Uniper announced a non-binding Heads of Agreement together with ConocoPhillips, for the potential sale of ammonia to Uniper. This agreement further advanced our cooperation to potentially develop a low-carbon, ammonia production facility on the U.S. Gulf Coast that would supply low-carbon fuels from the U.S. for use in the U.S., Europe, Japan and greater Asia.

Delivery Commitments

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 440 billion cubic feet of natural gas, 275 million barrels of crude oil and 15.9 million megawatt hours of electricity in the future. These contracts have various expiration dates through the year 2030. We expect to fulfill these delivery commitments with third-party purchases, as supported by our gas management and power supply agreements; proved developed reserves and PUDs. See the disclosure on “Proved Undeveloped Reserves” in the “Supplementary Data - Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of PUDs.

Competition

ConocoPhillips is one of the world’s leading E&P companies based on both production and reserves, with a globally diversified asset portfolio. We compete with private, public and state-owned companies in all facets of the E&P business. Some of our competitors are larger and have greater resources. Each of our segments is highly competitive, with no single competitor, or small group of competitors, dominating.

We compete with numerous other companies in the industry, including state-owned companies, to locate and obtain new sources of supply and to produce oil, bitumen, NGLs and natural gas in an efficient, cost-effective manner. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; equipment and personnel; economic analysis in connection with portfolio management and safely operating oil and gas producing properties.


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Business and Properties			Table of Contents

Human Capital Management

Values, Principles and Governance

At ConocoPhillips, our strategy, performance, culture and reputation are fueled by our workforce. We recognize that attracting, retaining, and developing talent is a competitive imperative within our changing industry. Our human capital management (HCM) approach starts with a foundation in our core SPIRIT Values – Safety, People, Integrity, Responsibility, Innovation, and Teamwork. These SPIRIT Values set the tone for how we interact with all of our internal and external stakeholders. We believe a safe organization is a successful organization, and therefore, we prioritize personal and process safety across the company. Our SPIRIT Values are a source of pride. Our day-to-day work is guided by the principles of accountability and performance, which means the way we do our work is as important as the results we deliver. We believe these core values and principles set us apart, align our workforce and provide a foundation for our culture.

Our Executive Leadership Team (ELT) and our Board of Directors play a key role in setting our HCM strategy and driving accountability for meaningful progress. The ELT and Board of Directors engage often on workforce-related topics. Our HCM programs are overseen and administered by our human resources function with support from business leaders across the company.

We depend on our workforce to successfully execute our company’s strategy and we recognize the importance of creating a workplace where our people feel valued. Our HCM programs are built around three pillars that we believe are necessary for success: a compelling culture, attracting a world-class workforce and valuing our people. Each of these pillars is described in more detail below.

A Compelling Culture

How we do our work is what sets us apart and drives our performance. We are experts in what we do and continuously find ways to do our jobs better. Our different backgrounds, ideas and views drive our success. Together, we deliver strong performance, but not at all costs. We embrace our core cultural attributes that are shared by everyone, everywhere.

Health, Safety and Environment

Our HSE organization sets expectations and provides tools and assurance to our workforce to promote and achieve HSE excellence. We manage and assure ConocoPhillips HSE policies, standards and practices, to help ensure business activities are consistently safe, healthy and conducted in an environmentally and socially responsible manner across the globe. Each business unit manages its local operational risks with particular attention to process safety, occupational safety and environmental and emergency preparedness risk. Objectives, targets and deadlines are set and tracked annually to drive strong HSE performance. Progress is tracked and reported to our ELT and the Board of Directors. HSE audits are conducted on business units and staff groups to ensure conformance with ConocoPhillips HSE policies, standards and practices where improvement actions are identified and tracked to completion.

We continuously look for ways to operate more safely, efficiently and responsibly. We focus on reducing human error by emphasizing interaction among people, equipment and work processes. We believe our HSE policies such as Life Saving Rules, Process Safety Fundamentals, safety procedures and our stop work policy can reduce the likelihood and severity of unexpected incidents. We conduct thorough investigations of all serious incidents to understand the root cause and share lessons learned globally to improve our facility designs, procedures, training, maintenance programs and designs. It is important that we drive an HSE culture of continuous learning and improvement, refine our existing HSE processes and tools and enhance our commitment to safe, efficient and responsible operations.

Diversity, Equity and Inclusion

As our industry evolves, we will continue to face both new opportunities and challenges, requiring a workforce that is equipped to address this evolution. We also need to cultivate an environment where everyone is encouraged and able to contribute — no matter their role, level or location. This is how innovation thrives, leading to a better business outcome. That is why we have put an emphasis on, and are committed to, elevating DEI and creating a great place to work.

At ConocoPhillips, we believe our unique differences power the future of energy. Our DEI vision is to foster an inclusive culture that values the rich mixture of backgrounds, identities and workstyles of our people, built on equitable practices that support all employees in unlocking their full potential. Our commitment to DEI is foundational to our SPIRIT Values and to achieving our business objectives. All employees play a part in creating and sustaining an inclusive work environment because everyone benefits from DEI.


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The ELT has ultimate accountability for advancing our DEI commitments through a governance structure that includes a Chief Diversity Officer (CDO), a dedicated DEI organization and a global DEI Council consisting of senior leaders from across the company. The company sets goals and measures progress based on a transparent DEI strategy with four pillars that guide our focus and approach: people, programs and processes, culture and our external brand and reputation. All company leaders are accountable for advancing DEI through local efforts. Our DEI efforts and progress are regularly reviewed with the Board of Directors.

We continue to actively monitor diversity metrics on a global basis. We are committed to being transparent as we build a more diverse, equitable and inclusive workplace. Tables of 2023 employee demographics by gender and ethnicity, and by country, are shown below:

2023 Employees by Gender and Race/Ethnicity


	Global				U.S.
	Male		Female		White		POC*
All Employees	73	%	27	%	68	%	32	%
All Leadership	74		26		76		24
Top Leadership	74		26		82		18
Junior Leadership	74		26		74		26

*"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.


2023 Employees by Country	Percent of Total
U.S.	66	%
Norway	16
Canada	9

Australia	3
U.K.	3

Other Global Locations	3
	100	%

Attracting A World-Class Workforce

Our continued success requires a strong workforce with the right skills across the globe to achieve our strategic objectives. We recruit extensively for experienced hires with critical skills to help us sustain a broad range of expertise. We also offer university internships across multiple disciplines and partner with diversity organizations and universities to create a pipeline for early-career talent. We strive to ensure equitable practices in every aspect of our recruitment process and conduct talent assessments to ensure we have the organizational capacity and capabilities to successfully execute our business plans.

We closely monitor recruitment metrics through internal talent dashboards and track voluntary turnover metrics to guide our retention activities.


2023 Hiring & Attrition Metrics	Percent of Total
U.S. University hire acceptance	73	%
U.S. Interns acceptance	71
Diversity hiring - Women	27
Diversity hiring - U.S. POC	41
Total voluntary attrition	4


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Valuing our People

Employee Engagement and Development

We focus on the engagement and development of our workforce and encourage our employees to build diverse and fulfilling careers at ConocoPhillips. We develop our workforce through a combination of on-the-job learning, formal training, regular feedback, coaching and mentoring. Skills-based Talent Management Teams (TMTs) guide targeted employee development and career progression by skills, discipline and location. The TMTs help identify our workforce planning needs and assess the availability of critical skill sets within the company. We use a performance management program focused on objectivity, credibility and transparency. The program includes broad stakeholder feedback, real-time monetary and non-monetary recognition and a formal “how” rating to assess behaviors to ensure they align with our SPIRIT Values.

We empower our employees to grow their careers through personal and professional development opportunities, including individual development plans, annual career development conversations with supervisors, a voluntary 360-feedback tool and training on a broad range of technical and professional skills. Succession planning is a top priority for management and the Board of Directors. This work ensures we have the talent available for critical leadership roles and serves to inspire employees to reach their ultimate potential and limit business interruption.

Taking steps to measure and assess employee satisfaction and engagement is at the heart of long-term business success and creating a great place to work for our global workforce. Since 2019, the ConocoPhillips Perspectives Survey has become our primary listening platform for gathering feedback on employee sentiment and promoting our “Who We Are” culture. Our leadership reviews the survey feedback to guide priorities and goals. Our employee feedback strategy is delivered through this annual engagement survey and as needed; shorter ad hoc surveys are leveraged to unlock targeted insights in support of our human capital priorities.

Compensation, Benefits and Well-Being

We offer competitive, performance-based compensation packages and have global equitable pay practices. Our compensation programs are generally comprised of a base pay, the annual Variable Cash Incentive Program (VCIP) and, for eligible employees, the Restricted Stock Unit (RSU) program. From the CEO to the frontline worker, every employee participates in VCIP, our annual incentive program, which aligns employee compensation with ConocoPhillips’ success on critical performance metrics and also recognizes individual performance. Our RSU program is designed to attract and retain employees, reward performance and align employee interest with stockholders by encouraging stock ownership. Our retirement and savings plans are intended to support the financial futures of our employees and are competitive within local markets.

We routinely benchmark our global compensation and benefits programs to ensure they are competitive, inclusive, aligned with company culture and allow our employees to meet their individual needs and the needs of their families. We provide flexible work schedules and competitive time off, including parental leave policies in many locations. We also offer employees flexibility through the Hybrid Office Work (HOW) program in all of our global locations, which provides eligible employees a combination of work from both office and home. We also provide coverage for families requiring disability support, elder care and childcare, including onsite childcare, where access locally is a challenge.

Our global wellness programs include biometric screenings and fitness challenges designed to educate and promote a healthy lifestyle. All employees have access to our employee assistance program, and many of our locations offer custom programs to support mental well-being.

Compensation Risk Mitigation

We have considered the risks associated with each of our executive and broad-based compensation programs and policies. As part of the analysis, we considered the performance measures we use as well as the different types of compensation, varied performance measurement periods and extended vesting schedules that we utilize under each incentive compensation program. As a result of this review, management concluded that the risks arising from our compensation policies and practices are not reasonably likely to have a material adverse effect on the company. As part of the Board of Directors’ oversight of our risk management programs, the Human Resources Compensation Committee (HRCC) conducts a similar review with the assistance of its independent compensation consultant. The HRCC agrees with management’s conclusion that the risks arising from our compensation policies and practices are not reasonably likely to have a material adverse effect on the company.


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General

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 56 through 58 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2023 and those expected for 2024 and 2025.

Website Access to SEC Reports

Our internet website address is www.conocophillips.com. Information contained on our internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.


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Item 1A. Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any of these risks or other risks that are yet unknown or currently considered immaterial were to occur, our business, operating results and financial condition, as well as the value of an investment in our common stock, could be materially and adversely affected.

Risks Related to Our Industry

Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to the effects of volatile commodity prices or prolonged periods of low commodity prices.

Among the most significant factors impacting our revenues, operating results and future rate of growth are the sales prices for crude oil, bitumen, LNG, natural gas and NGL. These prices are tied to market prices that can fluctuate widely, and many of the factors influencing the prices are beyond our control. For example, over the course of 2023, WTI crude oil prices ranged from a low of $67 per barrel in March to a high of $94 per barrel in August. Given the volatility in commodity price drivers and the worldwide political and economic environment, including potential economic slowdowns or recessions, unexpected shocks to supply and demand resulting from future global health crises such as those experienced in connection with the COVID-19 pandemic or increased uncertainty generated by recent (and potential future) armed hostilities in various oil-producing regions around the globe, prices for crude oil, bitumen, LNG, natural gas and NGLs may continue to be volatile.

Prolonged periods of low commodity prices could have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock and the amount of shares we elect to acquire as part of our share repurchase program and the timing of such acquisitions. Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields. Prolonged depressed prices may affect strategic decisions related to our operations, including decisions to reduce capital investments or curtail operated production.

Significant reductions in crude oil, bitumen, LNG, natural gas and NGL prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved reserves. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-of-production rates at this time, our results of operations could be adversely affected as a result.

Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to our business.

As we produce crude oil, bitumen, natural gas and NGLs from our existing portfolio, the amount of our remaining reserves declines. If we do not successfully replace the resources we produce with good prospects for future organic development or through acquisitions, our business will decline. In addition, our ability to successfully develop our reserves depends on our achievement of a number of operational and strategic objectives, some aspects of which are beyond our control, including navigating political and regulatory challenges to obtain and renew rights to develop and produce hydrocarbons; reservoir optimization; bringing long-lead time, capital intensive projects to completion on budget and on schedule; and efficiently and profitably operating mature properties. If we are not successful in developing the resources in our portfolio, our financial condition and results of operations may be adversely affected.

The exploration and production of oil and gas is a highly competitive industry.

The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We compete with private, public and state-owned companies in all facets of the exploration and production business, including to locate, acquire and develop new sources of supply and to produce crude oil, bitumen, natural gas and NGLs in an efficient, cost-effective manner. In addition, as the energy transition progresses, we anticipate the oil and gas industry will face additional competition from alternative fuels. We must also compete for the materials, equipment, services, employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business. If we are not successful in any facet of this competition, our financial condition and results of operations may be adversely affected.


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Our ability to successfully execute on our energy transition plans is subject to a number of risks and uncertainties and may be costly to achieve.

In 2020, we announced our Paris-aligned climate risk framework, including an ambition to achieve net-zero operational emissions by 2050. In 2022, we published our Plan for the Net-Zero Energy Transition (the “Plan”) and continued to set increasingly ambitious targets around operational GHG emissions intensity and reducing methane emissions and flaring. Our ability to achieve stated targets, goals and ambitions is subject to a number of risks and uncertainties out of our control, government policies and markets, as well as potential regulations that may impair our ability to execute on current or future plans. Such achievement also depends on the accelerated pace of development of effective emissions measurement and abatement technologies, and the actual pace of development may be inadequate, or the technologies actually developed may be insufficient. Furthermore, we are still in the planning stages, and the Plan's execution could be costly, may have unforeseen obstacles, may proceed at varying paces during the timeframe allotted for the Plan and may be accomplished in a manner that we cannot predict at this time. We may be required to purchase emission credits in the future, and there may be an insufficient supply of offsets to achieve our goals, or we could incur increasingly greater expenses related to our purchase of such offsets. As advanced technologies are developed to accurately measure emissions, we may be required to revise our emissions estimates and reduction goals or otherwise revise our strategies outlined in the Plan. We may be adversely affected and potentially need to reduce economic end-of-field life of certain assets and impair associated net book value due to the emissions intensity of some of our assets. Even if we meet our goals, our efforts may be characterized as insufficient.

In 2021, we established our Low-Carbon Technologies organization to identify and evaluate business opportunities that address end-use emissions and early-stage low-carbon technology opportunities that would leverage our existing expertise and adjacencies. Our investments in these technologies may expose us to numerous financial, legal, operational, reputational and other risks. While we perform a thorough analysis on these investments, the related technologies and markets are at early stages of development and we do not yet know what rate of return we will achieve, if any. Furthermore, we may not be able to deploy such technologies at a commercial scale. The success of our low-carbon strategy will depend in part upon the cooperation of government agencies, the support of stakeholders, our ability to research and forecast potential investments, and our ability to apply our existing strengths and expertise to new technologies, projects and markets.

Estimates of crude oil, bitumen, natural gas and NGL reserves are imprecise and may be subject to revision, and any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and NGL reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report represents management’s best estimates based on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured, and the estimates and underlying assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property associated with the production of those reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and commodity prices. For more information on estimates used, see the "Critical Accountin g Estimates " section of Management's Discussion and Analysis of Financial Condition and Results of Operations.

Our business may be adversely affected by price controls; government-imposed limitations on production or exports of crude oil, bitumen, LNG, natural gas and NGLs; or the unavailability of adequate gathering, processing, compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen, natural gas and NGLs.

As discussed herein, our operations are subject to extensive governmental regulations across numerous jurisdictions. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, bitumen, natural gas and NGL wells below actual production capacity. Similarly, in response to increased domestic energy costs, circumstances determined to be in the economic interest of the country, or a declared national emergency, governments could restrict the export or import of our products which would adversely impact our business. Because legal requirements are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our business may be enacted or become applicable to us.


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Our ability to sell and deliver the crude oil, bitumen, LNG, natural gas and NGLs that we produce also depends on the availability, proximity, and capacity of gathering, processing, compression, transportation and pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, LNG, natural gas and NGLs for transport. The facilities, equipment and diluents we rely on may be temporarily unavailable to us due to market conditions, extreme weather events, permitting delays and other regulatory matters, mechanical reasons or other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells, and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil, bitumen, LNG, natural gas and NGLs for sale; we may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs or we may not be able to meet all the objectives in the Plan, such as reducing routine flaring.

Our ability to manage risk or influence outcomes in joint ventures may be constrained.

We conduct many of our operations through joint ventures in which another joint venture partner is operator or we may not have majority control. In these cases, the economic, business, or legal interests or goals of the operator or the voting majority may be inconsistent with ours, and we may not be able to influence the decision making or outcomes to align with our interests or goals. Failure by an operator or a voting majority, with whom we have a joint venture interest, to adequately manage the risks associated with any operations could have an adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

Our operations are subject to hazards and risks that require significant and continuous oversight.

Our operations are subject to a variety of hazards and risks that require significant and continuous oversight, such as the monitoring, prevention or mitigation of or protection from explosions, fires, product spills, severe weather, geological events, global health crises, such as epidemics and pandemics, labor disputes, geopolitical tensions, armed hostilities, terrorist or piracy attacks, sabotage, civil unrest or cyberattacks. Our operations are subject to additional hazards concerning exposure to and potential release of pollutants and toxic substances, as well as other environmental hazards and risks. For example, offshore activities may pose incrementally greater risks because of complex subsurface conditions such as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation. Our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to efficiently restore or replace affected operational components and capacity. Countermeasures to address global health crises, epidemics or pandemics, including future outbreaks of COVID-19, may result in reduced demand for our products; disruptions to our supply chain, the global economy or financial or commodity markets; disruptions in our contractual arrangements with our service providers, suppliers and other counterparties; failures by our suppliers, contract manufacturers, contractors, joint venture partners and external business partners, to meet their obligations to us; reduced workforce productivity; and voluntary or involuntary curtailments. Further, our insurance may not be adequate to compensate us for all resulting losses described above, and the cost to obtain adequate coverage may increase for us in the future or may not be available.

In addition, although we design and operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the earth's climate, such as more severe or frequent weather conditions in the markets where we operate or the areas where our assets reside, we could incur increased expenses, our operations and supply chain could be adversely impacted and demand for our products could fall.

Any of these factors, or other cascading effects of such factors, could materially increase our costs; negatively impact our revenues or ability to implement and advance the Plan; and damage our financial condition, results of operations, cash flows and liquidity position. The full extent and duration of any such impacts cannot be predicted at this time because of the lack of certainty surrounding their sources, causes and outcomes.


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Legal and Regulatory Risks

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.

Our business is subject to numerous laws and regulations relating to the protection of the environment, which are expected to continue to have an increasing impact on our operations. For a description of the most significant of these environmental laws and regulations, see the “Contingencies—Environmental”, “—Climate Change” and "—Company Re sponse to Climate-Related Risks" sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

•Permits required in connection with exploration, drilling, production and other activities, including those issued by national, subnational, and local authorities;

•The discharge of pollutants into the environment;

•Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions, including methane;

•Carbon taxes;

•The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes;

•The dismantlement, abandonment and restoration of historic properties and facilities at the end of their useful lives; and

•Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and unconventional plays.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. In addition, to the extent these expenditures are assumed by a buyer as a result of a disposition, it may result in our incurring substantial costs if the buyer is unable to satisfy these obligations. Any actual or perceived failure by us to comply with existing or future laws, regulations and other requirements could result in administrative or civil penalties, criminal fines, other enforcement actions or third-party litigation against us. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our business, financial condition, results of operations and cash flows in future periods as well as our ability to implement and advance the Plan could be adversely affected.

Existing and future laws, regulations and internal initiatives relating to global climate change, 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.

Continuing political and societal attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions, such as cap and trade regimes, specific emission standards, carbon taxes, restrictive permitting, increased fuel efficiency standards, and incentives or mandates for renewable and alternative energy. Although we may support the intent of legislative and regulatory measures aimed at addressing climate-related risks, the specifics of how and when they are enacted could result in a material adverse effect to our business, financial condition, results of operations and cash flows in future periods as well as our ability to implement and advance the Plan.

For example, in December 2023, the EPA published a final rule that revises the regulations governing, among other things, the emission of methane and volatile organic compounds from new oil and gas production facilities, and emission guidelines for states to use when revising Clean Air Act implementation plans to limit methane emissions from existing oil and gas facilities. The final rule could result in additional capital expenditures and compliance, operating and maintenance costs, any of which may have an adverse effect on our business and results of operations.

Additionally, in 2023, the U.S. joined the international community at the 28th Conference of the Parties (COP28), where the U.S. and nearly 200 other countries, including most of the countries in which we operate, renewed their commitment to deliver on the aims of the 2015 Paris Agreement. COP28 included a decision on the world's first 'global stocktake' to ratchet up climate action before the end of the decade — including a goal to triple renewable energy capacity by 2030 — and for the first time its final agreement explicitly recommended "transitioning away from fossil fuels in the energy system." The implementation of current agreements and regulatory measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely increase our capital and operating expenses,


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impact the demand for our products, impose taxes on our products or operations, or require us to purchase emission credits or reduce emissions of GHGs from our operations. For example, in August 2022, the U.S. enacted the Inflation Reduction Act of 2022, which includes a charge on methane emissions from selected facilities in the oil and gas industry, including many of the facilities operated by ConocoPhillips. As a result, we may incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations.

For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company's response, see the "Contingencies—Climate Change” and "—Company Response to Climate -Related Risks " sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Broader investor and societal attention to and efforts to address global climate change may limit who can do business with us or our access to financial markets and could subject us to litigation.

Increasing attention to global climate change has also resulted in pressure from and upon stockholders, financial institutions and other financial market participants to potentially limit or discontinue investments, insurance and funding to oil and gas companies. For example, a significant number of financial institutions are now members of the Glasgow Financial Alliance for Net Zero (GFANZ), thereby pledging to the goal of net zero by 2050, as well as setting interim targets for 2030 or earlier. While they are not prohibited from doing business with oil and gas companies, GFANZ members may self-impose limits. Conversely, we also face pressure from some in the investment community and certain public interest groups to limit the focus on ESG in our decision-making, arguing that ESG considerations do not relate to financial outcomes. As public pressure continues to mount on the financial sector, our costs of capital may increase.

Furthermore, increasing attention to global climate change has resulted in an increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Beginning in 2017 and continuing through 2023, cities, counties, governments and other entities in several states/territories in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless, and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we expect to incur substantial legal costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a failure or lack of diligence to meet our publicly stated ESG goals, or alleging misrepresentation related to our ESG activity.

Political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation, executive orders and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest groups. In addition, we may face regulatory changes in the U.S. including, but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane emissions standards, requirements restricting or prohibiting flaring and subsurface water disposal, more stringent environmental impact studies and reviews and policies inhibiting or curtailing LNG exports. Similar regulatory shifts, including attendant higher costs and market access constraints, may also occur in international jurisdictions in which we operate.

Hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations, has historically attracted political and regulatory scrutiny. A range of local, state, federal and national laws and regulations currently govern, constrain or prohibit hydraulic fracturing in some jurisdictions. New or more stringent permitting, disclosure or other regulatory requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal, could result in increased costs, operating restrictions or operational delays or could limit the ability to develop oil and natural gas resources.

In addition, certain interest groups have also proposed ballot initiatives, contested lease sales and challenged project permits, for example, to restrict oil and natural gas development generally as well as specific projects, including the


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Willow project in Alaska. In the event that ballot initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations on the production and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the permitting or pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, liquidity and ability to implement and advance the Plan.

Political and economic factors in international markets could have a material adverse effect on us.

Approximately 31 percent of our hydrocarbon production was derived from production outside the U.S. in 2023, and 33 percent of our proved reserves, as of December 31, 2023, were located outside the U.S. We are subject to risks associated with our operations in foreign jurisdictions and international markets, including changes in foreign governmental policies relating to crude oil, bitumen, LNG, natural gas or NGL pricing and taxation; other regulatory or economic developments (including the macro effects of international trade policies and disputes); disruptive geopolitical conditions, and international monetary and currency rate fluctuations. For example, in December 2022, in response to higher energy prices resulting from the conflict between Russia and Ukraine, Australia’s Parliament passed legislation setting a one-year price cap on natural gas. Further legislation was introduced in 2023 that extends the price cap through to at least June 2025, subject to further review and certain exemptions. Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable approach for pursuing national and global energy security and climate policies. The escalation of geopolitical tension in the Middle East in late 2023 and early 2024 underscores the continued relevance of this consideration. In addition, some countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as expropriations. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan government, have affected operations significantly in the past and may continue to do so in the future.

In addition, the U.S. government has the authority to prevent or restrict us from doing business in foreign jurisdictions or with certain parties. These restrictions and similar restrictions imposed by foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various jurisdictions. Diplomatic relations or policies between the U.S. government and one or more foreign jurisdictions may impair our ability to collect awards in legal actions against such foreign jurisdictions. Changes in domestic and international policies and regulations may also restrict our ability to obtain or maintain licenses or permits necessary to operate in foreign jurisdictions, including those necessary for drilling and development of wells. Similarly, the declaration of a “climate emergency” could result in actions to limit exports of our products and other restrictions.

Any of these actions could adversely affect our business or operating results, including our ability to implement and advance the Plan.

Other Risk Factors Facing our Business or Operations

We may need additional capital in the future, and it may not be available on acceptable terms or at all.

We have historically relied primarily upon cash generated by our business to fund our operations and strategy; however, we have also relied from time to time on access to the capital markets for funding. There can be no assurance that additional financing will be available in the future on acceptable terms or at all. In addition, although we anticipate we will be able to repay our existing indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able to do so. Our ability to obtain additional financing or refinance our existing indebtedness when it matures or in accordance with our plans, will be subject to a number of factors, including market conditions, our operating performance, investor sentiment, risks impacting financial institutions and the credit markets more broadly and financial institution policies regarding the oil and gas industry. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, our business could be adversely affected.

In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our financial strength and conditions affecting the oil and gas industry generally. We and other industry companies have had our ratings reduced in the past due to negative commodity price outlooks. These major rating agencies are now considering ESG attributes when assessing credit profiles. While these assessments have limited impact today, they have the potential to pressure credit ratings over time. Any downgrade in our credit rating or announcement that our credit rating is under review for possible downgrade could increase the cost associated with any additional indebtedness we incur.


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Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts with, third-parties with whom we do business.

The operation of our business requires us to engage in transactions with numerous counterparties operating in a variety of industries, including other companies operating in the oil and gas industry. These counterparties may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity issues they are experiencing. Any default by any of our counterparties may result in our inability to perform our obligations under agreements we have made with third-parties or may otherwise adversely affect our business or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting counterparty, which could further adversely impact our results of operations.

Our ability to execute our capital return program is subject to certain considerations.

In December 2021, we initiated a three-tier capital return program that consists of our ordinary dividend, share repurchases and a variable return of cash (VROC).

Ordinary dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:

•Cash available for distribution;

•Our results of operations and anticipated future results of operations;

•Our financial condition, especially in relation to the anticipated future capital needs of our properties;

•The level of distributions paid by comparable companies;

•Our operating expenses; and

•Other factors our Board of Directors deems relevant.

VROC distributions are also authorized and determined by our Board of Directors in its sole discretion and depend upon a number of factors, including:

•The anticipated level of distributions required to meet our capital returns commitment;

•Forward prices;

•The amount of cash we hold;

•Total yield; and

•Other factors our Board of Directors deems relevant.

We expect to continue to pay a quarterly ordinary dividend to our stockholders. In addition, based on the current environment, we anticipate also paying a quarterly VROC to our shareholders; however, the amount of dividends and VROC is variable and will depend upon the above factors, and our Board of Directors may determine not to pay a dividend or VROC in a quarter or may cease declaring a dividend or VROC at any time. Since the inception of the three-tier return of capital program, the VROC has both increased and decreased across quarters, and it may continue to fluctuate in the future.

Additionally, as of December 31, 2023, $16.2 billion of repurchase authority remained of the $45 billion share repurchase program our Board of Directors had authorized. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board of Directors may consider when declaring dividends, among other factors. In the past we have suspended our share repurchase program in response to market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so again in the future.

Any downward revision in the amount of our ordinary dividend or VROC or the volume of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.


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There are substantial risks with any acquisitions or divestitures we have completed or that we may choose to undertake.

We regularly review our portfolio and pursue growth through acquisitions and seek to divest noncore assets or businesses. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. Even if we do complete such transactions, our cash flow from operations may be adversely impacted or otherwise the transactions may not result in the benefits anticipated due to various risks, including, but not limited to (i) the failure of the acquired assets or businesses to meet or exceed expected returns, including risk of impairment; (ii) the inability to dispose of noncore assets and businesses on satisfactory terms and conditions; and (iii) the discovery of unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections are inadequate or we lack insurance or indemnities, including environmental liabilities, or with regard to divested assets or businesses, claims by purchasers to whom we have provided contractual indemnification. In addition, we may face difficulties in integrating the operations, technologies, products and personnel of any acquired assets or businesses.

Our technologies, systems and networks are subject to cybersecurity threats.

Our business is faced with growing cybersecurity threats as we increasingly rely on digital technologies across our business. Cybersecurity risks to our business, including our suppliers, third-party service providers, contractors, joint venture partners and external business partners, include but are not limited to:

•Unauthorized access to, or control of or disclosure of sensitive information about our business and our employees;

•Compromise of our data or systems, including corruption, sabotage, encryption or acts that otherwise render our data or systems unusable (or those of third-parties with whom we do business, including third-party cloud and information technology (IT) service providers);

•Theft or manipulation of our proprietary information;

•Ransom;

•Extortion;

•Threats to the security of our facilities and infrastructure; and

•Cyber terrorism.

In addition, we have exposure to cybersecurity risks where our data and proprietary information are collected, hosted, and/or processed by third-party cloud and service providers. Our risks may be exacerbated by a delay or failure to detect a cybersecurity incident or understand the full extent of such incident notwithstanding our risk management processes and controls. We face risks associated with new and ever-increasing phishing techniques, hidden malware, as well as risks associated with electronic data proliferation and technology digitization. We also face increased risk with the increased sophistication of Generative Artificial Intelligence capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time.

Our increasing reliance on IT in our production, distribution and marketing systems may allow cybersecurity threats to disrupt our oil and gas operations, both domestically and abroad.

If our data, IT, operational technology (OT), including industrial control and supervisory control and data acquisition (SCADA) systems were to be breached, damaged or disrupted due to a cybersecurity incident or cyber-attack (directly, indirectly through third-parties or through the IT networks, servers, software, or infrastructure on which they rely), we could be subject to serious negative consequences. These consequences could include physical damage to production, distribution or storage assets; delay or prevention of delivery to markets; disruption or prevention of accurate accounting for production and settlement of transactions; negative impacts on public health, safety, the environment, economic security, or national security; financial impacts; business interruption; reputational damage; loss of employee, supplier, contractor, partner and/or public trust; reimbursement or other costs; increased compliance costs; regulatory investigations; litigation exposure and legal liability or regulatory fines; penalties or other external intervention.

Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and infrastructure that support our business. Further, our ability to insure against cybersecurity risks may be limited by the availability and increasing expense of sufficient coverage.

For additional information regarding our cybersecurity risk management, strategy and governance, see I tem 1C. Cyber s ecurity.


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Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Cybersecurity Risk Management and Strategy

Cybersecurity Risk Assessment and Management

We take a multilayered approach to cybersecurity risk management and strategy. Our IT/OT Security Program integrates administrative, technical, and physical controls against evolving cybersecurity threats, and includes enterprise IT and OT security architecture, cybersecurity operations, data privacy and governance, supply chain security, and governance, risk, and compliance. Additionally, it is designed to identify, assess, and manage cybersecurity risks and protect the confidentiality, integrity, and availability of our data, IT, and OT.

Cybersecurity is a component of our IT/OT Security Program, which we periodically review and adapt to respond to new and evolving circumstances, cybersecurity threats and regulations. We evaluate security, privacy, and resiliency risks, including those related to cybersecurity, in our overall Enterprise Risk Management (ERM) program's annual risk assessment process. This annual risk assessment process takes into account broader risks based on likelihood, potential consequences, and mitigations, such as operational and economic impact; health, safety and environmental impact; and reputational and financial implications. This risk assessment is discussed with members of the ELT, Audit and Finance Committee (AFC) of the Board of Directors, and Board of Directors on at least an annual basis.

We consult recognized security frameworks, such as the National Institute of Standards and Technology Cybersecurity Framework to organize, improve, and assess our IT/OT Security Program to manage and reduce cybersecurity risk. We deploy, configure, and maintain various technologies designed to enforce security policies, detect and protect against cybersecurity threats, and help safeguard IT and OT assets. We operate a Cybersecurity Operation Center (CSOC) to ingest threat intelligence, monitor cybersecurity threats, coordinate incident response resources and manage response times.

Our Global Computer Security Incident Response Plan (CSIRP) establishes the framework for our response to cybersecurity incidents. Under the CSIRP, cybersecurity incidents are escalated based on a defined incident categorization to the Chief Information Security Officer (CISO) and senior leaders, including the Chief Digital & Information Officer (CD&IO), General Counsel, Chief Financial Officer, and other cybersecurity program stakeholders, such as the AFC and/or the full Board of Directors. We also conduct incident response exercises at least annually, which are facilitated by internal team members and, in some instances, with assistance from third-party experts.

Physical controls are designed to work in conjunction with digital and cybersecurity controls to help protect the Company’s IT and OT assets from physical threats. Our Chief Security Officer is responsible for a physical security program including site plans, cameras, security systems monitoring, and access control and badging systems to manage physical security risks.

Our governing policies, standards and procedures create a structured approach to managing cybersecurity risk. Information security requirements for employees, contractors and partners are detailed in the ConocoPhillips Information Security & Protection Policy. Our workforce is required to complete information security training annually, and we periodically communicate ways to recognize and avoid cybersecurity threats to our workforce.


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Engagement of Third Parties

We engage third-party cybersecurity consultants and experts to supplement staffing of our CSOC, as well as to help us assess, validate, and enhance our security practices, including conducting cybersecurity maturity assessments, vulnerability assessments and penetration tests.

As part of the cybersecurity incident response process described above, we engage third-party experts as needed to support incident response, such as external legal advisors, cybersecurity forensic firms and other specialists.

Third Party Service Provider Risk Management

Our third-party risk management process is designed to identify, assess, and mitigate risks associated with third-party service providers, including cybersecurity risks. An initial assessment is conducted to assess the cybersecurity risks associated with a third-party provider based on various criteria, such as whether the third-party provider has access to our network, data, and information systems. Third-party providers that are identified through the initial assessment as warranting further review are subject to additional risk assessment. In parallel, we have designed a contracting process to mitigate cybersecurity risks by specifying the rights and responsibilities of the parties.

Risks from Material Cybersecurity Threats

While we are subject to ongoing cybersecurity threats, we do not believe that the risks from previous threats have materially affected or are reasonably likely to materially affect the company, including our business strategy, results of operations or financial condition. Nevertheless, we recognize cybersecurity threats are on-going and evolving, and our program is designed to identify and manage those threats. See item 1A . Risk Factors —Our technologies, systems and networks are subject to cybersecurity threats for more information on our risks relating to our technologies, systems, and networks.

Cybersecurity Governance

Management's Role

A dedicated CISO leads the IT/OT Security Team and is responsible for our cybersecurity risk management and strategy. The CISO has over 20 years of experience in security, of which 15 years is specific to cybersecurity and has served as a CISO since 2013, having joined ConocoPhillips as CISO in 2022. The CISO holds a master’s degree and is a Certified Information Security Professional. The CISO reports to the CD&IO, who holds a master’s degree in information technology and has served as Chief Information Officer/Chief Technology Officer and various roles in information technology for over 27 years. The CD&IO reports to the Executive Vice President, Strategy, Sustainability and Technology. This management team assesses and manages risks associated with cybersecurity.

Board of Directors' Oversight

While our cybersecurity management team is responsible for the day-to-day assessment and management of material risks from cybersecurity threats, the ConocoPhillips Board of Directors has oversight responsibility for our ERM program and the individual risk management programs comprising our ERM program, including cybersecurity risk management. To help maintain effective Board of Directors' oversight across the entire enterprise, the Board of Directors delegates certain elements of its oversight function to individual committees. The AFC assists the Board of Directors in fulfilling its oversight of our ERM program and cybersecurity.

The Board of Directors receives a report on cybersecurity annually, and the AFC receives reports on cybersecurity twice a year. For meetings where cybersecurity is not on the formal agenda, the AFC will receive a pre-read that includes cybersecurity updates or discussion topics. During these reviews, management discusses various topics, including information relating to IT/OT Security strategy, program management, cybersecurity risks and threats, and provides briefings on notable cybersecurity attacks, including those relating to third-party service providers, if known. In addition to this regular reporting, significant cybersecurity risks or threats may also be escalated on an as needed basis to the AFC and Board of Directors.


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Item 3. Legal Proceedings

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would not be a material effect to our consolidated financial position.

ConocoPhillips has elected to use a $1 million threshold for disclosing certain proceedings arising under federal, state or local environmental laws when a governmental authority is a party. ConocoPhillips believes proceedings under this threshold are not material to ConocoPhillips' business and financial condition. Applying this threshold, there are no such proceedings to disclose for the year ended December 31, 2023. See Note 11 for information regarding other legal and administrative proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

Information about our Executive Officers


Name	Position Held	Age*
William L. Bullock, Jr.	Executive Vice President and Chief Financial Officer	59
Christopher P. Delk	Vice President, Controller and General Tax Counsel	54
C. William Giraud	Senior Vice President, Corporate Planning and Development	44
Heather G. Hrap	Senior Vice President, Human Resources and Real Estate and Facilities Services	51
Kirk L. Johnson	Senior Vice President, Lower 48 Assets and Operations	48
Ryan M. Lance	Chairman of the Board of Directors and Chief Executive Officer	61
Andrew D. Lundquist	Senior Vice President, Government Affairs	63
Dominic E. Macklon	Executive Vice President, Strategy, Sustainability and Technology	54
Andrew M. O'Brien	Senior Vice President, Global Operations	49
Nicholas G. Olds	Executive Vice President, Lower 48	54
Kelly B. Rose	Senior Vice President, Legal, General Counsel	57

_____________________

*On February 15, 2024.

There are no family relationships among any of the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from the date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 14, 2024. Set forth below is information about the executive officers.

William L. Bullock, Jr. was appointed Executive Vice President and Chief Financial Officer as of September 2020, having previously served as President, Asia Pacific & Middle East since April 2015. Prior to that, he was Vice President, Corporate Planning & Development since May 2012.

Christopher P. Delk was appointed Vice President, Controller and General Tax Counsel in November 2022, having previously served as Vice President and General Tax Counsel since July 2015.

C. William Giraud was appointed Senior Vice President, Corporate Planning and Development in June 2023, having previously served as Vice President, Corporate Planning and Development since May 2022. Prior to that, he served as Vice President and Chief Commercial Officer from February 2021 to April 2022. Prior to joining ConocoPhillips, he was Executive Vice President and Chief Operating Officer of Concho Resources.


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Heather G. Hrap was appointed Senior Vice President, Human Resources and Real Estate and Facilities Services in March 2022, having previously served as Vice President, Human Resources from January 2019. Prior to that, she served as Human Resources General Manager from October 2015 to January 2019.

Kirk L. Johnson was appointed Senior Vice President, Lower 48 Assets and Operations in May 2022, having previously served as Vice President, Corporate Planning and Development since June 2021. Prior to that he served as President Canada from June 2018 to May 2021 and Manager, Strategy, Planning and Portfolio Management from July 2017 to June 2018.

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having previously served as Senior Vice President, Exploration and Production—International since May 2009.

Andrew D. Lundquist was appointed Senior Vice President, Government Affairs in February 2013. Prior to that, he served as managing partner of BlueWater Strategies LLC, since 2002.

Dominic E. Macklon was appointed Executive Vice President, Strategy, Sustainability and Technology in September 2021, having previously served as Senior Vice President, Strategy, Exploration and Technology since August 2020. Prior to that, he served as President, Lower 48 from June 2018 to August 2020, Vice President, Corporate Planning & Development from January 2017 to June 2018, President, U.K. from September 2015 to January 2017, and Senior Vice President, Oil Sands in Canada from July 2012 to September 2015.

Andrew M. O'Brien was appointed Senior Vice President, Global Operations in November 2022, having previously served as Vice President and Treasurer since May 2021. Prior to that, he served as Vice President of Corporate Planning and Development from August 2020 to May 2021, Lower 48 Finance Manager from August 2018 to August 2020, and Manager of Investor Relations from November 2016 to August 2018.

Nicholas G. Olds was appointed Executive Vice President, Lower 48 in November 2022, having previously served as Executive Vice President, Global Operations since September 2021. Prior to that, he served as Senior Vice President, Global Operations from August 2020 to September 2021, Vice President, Corporate Planning & Development from June 2018 to August 2020, Vice President, Mid-Continent Business Unit, Lower 48 from September 2016 to June 2018, and Vice President, North Slope Operations and Development in Alaska from August 2012 to September 2016.

Kelly B. Rose was appointed Senior Vice President, Legal, General Counsel in September 2018. Prior to that, she was a senior partner in the Houston office of an international law firm, Baker Botts L.L.P., where she counseled clients on corporate and securities matters. She began her career at the firm in 1991.


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			Table of Contents

Part II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

ConocoPhillips’ common stock is traded on the New York Stock Exchange under the symbol “COP.”

Cash Dividends Per Share


	2023			2022
	Ordinary		VROC	Ordinary	VROC
First	$	0.51	0.60	0.46	0.30
Second	0.51		0.60	0.46	0.70
Third	0.51		0.60	0.46	1.40
Fourth	0.58		—	0.51	0.70
Number of Stockholders of Record at January 31, 2024*					34,675

Dividends shown above reflect the quarter in which the dividend was declared.

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency listing.

In December 2021, we announced the addition of a VROC tier to our return of capital program. The declaration of ordinary dividends and VROC are subject to the discretion and approval of our Board of Directors. The Board has adopted a dividend declaration policy providing that the declaration of any dividends will be determined quarterly. Beginning in the first quarter of 2024, ConocoPhillips plans to pay its quarterly dividend and VROC concurrently, and will announce such payments in the same quarter they will be paid. For more information on factors considered when determining the level of these distributions, see “Item 1A —Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

Issuer Purchases of Equity Securities


					Millions of Dollars
Period	Total Number of Shares Purchased*	Average Price Paid Per Share		Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

October 1-31, 2023	1,738,637	$	120.51	1,738,637	$	17,081
November 1-30, 2023	2,850,623	115.63		2,850,623	16,752
December 1-31, 2023	4,892,876	114.62		4,892,876	16,191
	9,482,136			9,482,136

* There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.

In late 2016, we initiated our current share repurchase program. In October 2022, our Board of Directors approved an increase to our authorization from $25 billion to $45 billion of common stock to support our plan for future share repurchases. As of December 31, 2023, we had repurchased $28.8 billion of shares. Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Except as limited by applicable legal requirements, repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares. For more information, see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”


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			Table of Contents

Stock Performance Graph

The following graph shows the cumulative TSR for ConocoPhillips’ common stock in each of the five years from December 31, 2018 to December 31, 2023. The graph also compares the cumulative total returns for the same five-year period with the S&P 500 Index and our performance peer group consisting of Chevron, ExxonMobil, APA Corporation, Pioneer, Devon, Occidental, Hess, and EOG weighted according to the respective peer’s stock market capitalization at the beginning of each annual period. In 2023, we have updated our performance peer group, removing Marathon Oil Corporation and adding Pioneer, to better align with our business and market capitalization.

The comparison assumes $100 was invested on December 31, 2018, in ConocoPhillips stock, the S&P 500 Index and ConocoPhillips’ peer group and assumes that all dividends were reinvested. The cumulative total returns of the peer group companies' common stock do not include the cumulative total return of ConocoPhillips’ common stock. The stock price performance included in this graph is not necessarily indicative of future stock price performance.


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Management’s Discussion and Analysis			Table of Contents

Item 7. 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 and uncertainties that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “ambition,” “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 65.

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 both production and reserves with operations and activities in 13 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe, Africa and Asia; global LNG developments; oil sands in Canada; and an inventory of global exploration prospects. Headquartered in Houston, Texas, at December 31, 2023, we employed approximately 9,900 people worldwide and had total assets of $96 billion.

Overview

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

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

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

Total company production in 2023 was 1,826 MBOED, yielding cash provided by operating activities of $20 billion. We invested $11.2 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of approximately $11 billion through our ordinary dividend, share repurchases and our VROC. For 2023, we returned $2.6 billion from our ordinary dividend, which included an increase from 51 cents per share to 58 cents per share, effective in December. We also returned $3.0 billion to shareholders from the VROC in 2023. In total for 2023, we returned $5.4 billion to shareholders through share repurchases. As of December 31, 2023, we have repurchased $28.8 billion of the $45 billion authorized share repurchase program. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. We also declared a first quarter ordinary dividend of 58 cents per share and a VROC of 20 cents per share.

In March, the Department of Interior published its ROD approving our Willow project in Alaska, which adopted a plan consisting of three core pads. In December, following a Ninth Circuit Court of Appeals denial of a request for an injunction, we reached FID on the Willow project and began winter construction.


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Management’s Discussion and Analysis			Table of Contents

In October, we completed our acquisition of the remaining 50 percent working interest in Surmont, an asset in our Canada segment, for $2.7 billion of cash after customary adjustments. The transaction was funded by proceeds received via long-term debt offerings. This transaction includes a contingent payment arrangement of up to an additional $0.4 billion CAD (approximately $0.3 billion) over a five-year term. 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. S ee Note 3.

In 2023, we took several steps to further our global LNG business. In March, we completed our acquisition of 30 percent equity interest in PALNG Phase 1. In June, we completed our acquisition of a 25 percent equity interest in NFS3 in Qatar. Additionally, in June, we signed a 20-year offtake agreement at the Saguaro LNG export facility on the west coast of Mexico, subject to Mexico Pacific reaching FID and other certain conditions precedent. Furthermore, in September, we signed a 15-year throughput agreement securing regasification capacity at the Gate LNG terminal in the Netherlands. See Note 3.

In the second quarter of 2023, we completed a strategic debt refinancing that extends the weighted average maturity of our portfolio from 15 to 17 years and reduces near term debt maturities. See Note 9.

In April, we announced that we are accelerating our operations 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 December, we achieved the Gold Standard Pathway in the Oil and Gas Methane Partnership (OGMP) 2.0 Initiative. For more information on our commitment to ESG and the Plan, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.

Operationally, we remain focused on safely executing the business. Our Lower 48 segment achieved record production in 2023. Our international projects reached several key operational milestones, including first production ahead of schedule at several subsea projects in Norway and China, as well as the startup of the second phase of Montney’s central processing facility in Canada. Production for 2023 was 1,826 MBOED, representing an increase of 88 MBOED or 5 percent compared to 2022. After adjusting for closed acquisitions and dispositions, production increased by 73 MBOED or 4 percent.

Key Operating and Financial Summary

Significant items during 2023 and recent announcements included the following:

•Generated cash provided by operating activities of $20.0 billion;

•Distributed $11.0 billion to shareholders through a three-tier framework, including $5.6 billion through the ordinary dividend and VROC and $5.4 billion through share repurchases;

•Ended the year with cash, cash equivalents, and restricted cash of $5.9 billion and short-term investments of $1.0 billion;

•Delivered record full-year total and Lower 48 segment production of 1,826 MBOED and 1,067 MBOED, respectively;

•Acquired the remaining 50 percent working interest in Surmont for approximately $2.7 billion as well as future contingent payments of up to $0.4 billion CAD ($0.3 billion);

•Took FID on the Willow project;

•Progressed global LNG strategy through expansion in Qatar, FID at PALNG and regasification agreements in the Netherlands and offtake agreements in Mexico;

•Reached first production at several subsea tiebacks in Norway, Surmont Pad 267 in Canada and Bohai Phase 4B in China;

•Commenced startup at the second phase of Montney's central processing facility in Canada;

•Awarded the Gold Standard Pathway designation by OGMP 2.0; and

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


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Management’s Discussion and Analysis			Table of Contents

Business Environment

The energy industry has historically been subject to volatility in commodity prices, which fluctuate with the global economy's supply and demand for energy. For example, WTI crude oil prices averaged $78 per barrel in 2023, compared with $94 per barrel in 2022. Our profitability, reinvestment of cash flows and distributions to shareholders are influenced by these fluctuations. Our Triple Mandate and foundational principles guide our differential value proposition to deliver competitive returns on and of capital to stockholders through price cycles. Our foundational principles consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments and demonstrating responsible and reliable ESG performance, all of which support strong financial returns and mitigate uncertainty associated with volatile commodity prices.

•Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price cycles. We strive to maintain our ‘A’-rating, as we did throughout 2023. In 2023, we initiated and completed a strategic debt refinancing to extend the weighted average maturity of our portfolio and reduced near-term debt maturities. In addition, we also funded the acquisition of the remaining 50 percent working interest in Surmont from the proceeds of new long-term debt issuances. We ended the year with cash and cash equivalents and restricted cash of $5.9 billion and short-term investments of $1.0 billion, maintaining balance sheet strength.

•Peer leading distributions. We believe in delivering value to our shareholders via our three-tiered return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and our VROC. This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders. In 2023, we returned $5.6 billion to shareholders through our ordinary dividend and VROC and $5.4 billion through share repurchases. Our combined dividends and share repurchases of $11 billion represented over 50 percent of our net cash provided by operating activities. In February 2024, we announced our 2024 planned return of capital to shareholders of $9 billion through our three-tier return of capital framework. See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain considerations.”

•Disciplined investments. Our goal is to achieve strong free cash flow by exercising capital discipline, controlling our costs, and safely and reliably delivering production. We expect to make capital investments sufficient to at least sustain production throughout the price cycles. Free cash flow is defined as cash from operations net of capital expenditures and investments and provides funds that are available to return to shareholders, strengthen the balance sheet or reinvest back into the business for future cash flow expansion.

◦Exercise capital discipline. We participate in a commodity price-driven and capital-intensive industry, with varying lead times from when an investment decision is made to when an asset is operational and generates cash flow. As a result, we must invest significant capital to develop newly discovered fields, maintain existing fields and construct pipelines and LNG facilities. We allocate capital across a geographically diverse, low cost of supply resource base, which combined with legacy assets results in low overall production decline. Cost of supply is the WTI equivalent price that generates a 10 percent after-tax return on a point-forward and fully burdened basis. Fully burdened basis includes capital infrastructure, foreign currency exchange rates, cost of carbon, price-related inflation and G&A. In setting our capital plans, we exercise a rigorous approach that evaluates projects using these cost of supply criteria, which we believe will lead to value maximization and cash flow expansion using an optimized investment pace, not production growth for growth’s sake. Our cash allocation priorities call for the investment of sufficient capital to sustain production and provide returns of capital to shareholders.

◦Control our costs. Controlling our costs, without compromising safety or environmental stewardship, is a high priority. Using various methodologies, we monitor costs monthly, on an absolute-dollar basis and a per-unit basis and report to management. Managing costs is critical to maintaining a competitive position in our industry, particularly in a low commodity price environment, and positively impacts our ability to deliver strong cash from operations.

◦Optimize our portfolio. We continue to evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2023, we completed the acquisition of the remaining 50 percent working interest in Surmont and completed our acquisitions of equity interests in both the PALNG and NFS3 LNG projects and signed both LNG offtake and regasification agreements. See Note 3.


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Management’s Discussion and Analysis			Table of Contents

◦Add to our proved reserve base. We primarily add to our proved reserve base in three ways:

▪Acquire interest in existing or new fields.

▪Apply new technologies and processes to improve recovery from existing fields.

▪Successfully explore, develop and exploit new and existing fields.

As required by authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is based on historical 12-month first-of-month average prices and current costs. This date estimates when production will end and affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production, as shown in our supplemental reserve table disclosures. Our reserve replacement was 123 percent in 2023, reflecting a net increase from development drilling activity, extensions and discoveries and purchases, partially offset by lower prices. Our organic reserve replacement, which excludes a net increase of 184 MMBOE from sales and purchases, was 96 percent in 2023.

In the three years ended December 31, 2023, our reserve replacement was 219 percent. Our organic reserve replacement during the three years ended December 31, 2023, which excludes a net increase of 1,293 MMBOE related to sales and purchases, was 152 percent. See "Supplementary Data - Oil and Gas Operations" for more information.

Access to additional resources may become increasingly difficult as lower commodity price cycles can make projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations, national fiscal terms, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to fully replace our production over subsequent years.

See "Item 1A—Risk Factors - Unless we successfully develop resources, the scope of our business will d ecline, resulting in an adverse impact to our busine ss."

•Environmental, Social and Governance performance. We seek to fulfill our mission of delivering energy to the world through an integrated management system that assesses sustainability-related business risks and opportunities as part of our decision-making process. Recognizing the importance of ESG performance to our stakeholders and company success, we have a governance structure that extends from the board of directors through to executive leadership and business unit managers.

In October 2020, we became the first U.S.-based oil and natural gas company to adopt a Paris-aligned climate risk framework that includes an ambition to achieve net-zero Scope 1 and 2 emissions on a gross operated and net equity basis by 2050. We believe that this framework, combined with our success in meeting the business objectives set by our Triple Mandate, represents the most effective way for us to sustainably contribute to society’s transition to a low-carbon economy. In 2023, we announced an acceleration of our operational GHG emissions intensity reduction target through 2030. In December, we achieved the Gold Standard Pathway in the OGMP 2.0 Initiative.

We believe that natural gas and oil will remain essential to the energy mix throughout the energy transition, and we also recognize the need for continuous reduction in the greenhouse gas intensity of production operations. The energy transition will likely be complex, evolving over multiple decades with many possible pathways and uncertainties. By following our Triple Mandate, we intend to meet this challenge in an economically viable, accountable and actionable way that creates long-term value for our stakeholders. For more information on our commitment to responsible and reliable ESG performance through the energy transition, see "Contingencies—Company Response to Climate-Related Risks" section of Management's Discussion and Analysis of Financial Condition and Results of Operation.


37			ConocoPhillips 2023 10-K


Management’s Discussion and Analysis			Table of Contents

Commodity Prices

Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices. Commodity price levels are subject to factors external to the company and over which we have no control, including but 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. The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas since 2021:

Brent crude oil prices averaged $82.62 per barrel in 2023, a decrease of 18 percent compared with $101.19 per barrel in 2022. Similarly, average WTI crude oil prices decreased 18 percent from $94.23 per barrel in 2022 to $77.62 per barrel in 2023. Prices were lower through 2023 as rising Non-OPEC supplies and Russia's ability to redirect crude oil to destinations outside the EU more than offset OPEC Plus crude oil supply curbs.

Henry Hub natural gas prices decreased 59 percent from an average of $6.65 per MMBTU in 2022 to $2.74 per MMBTU in 2023. Natural gas prices decreased due to mild winter weather and U.S. domestic supply growth outpacing demand growth.

Our realized bitumen price decreased 24 percent from an average of $55.56 per barrel in 2022 to $42.15 per barrel in 2023. The decrease was largely driven by weakness in WTI, reflective of global markets adjusting to new trade dynamics and global crude oil demand concerns. We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies.

Our worldwide annual average realized price decreased 27 percent from $79.82 per BOE in 2022 to $58.39 per BOE in 2023 primarily due to lower commodity p