mro-20221231

Proved reserves – Proved crude oil and condensate, NGLs and natural gas reserves are those quantities of crude oil and condensate, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation: our operational, financial and growth strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2023 capital budget and the planned allocation thereof; planned capital expenditures and the impact thereof; expectations regarding future economic and market conditions and their effects on us; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset potential; reserve estimates; expected interest expense; growth expectations; the impact of the Ensign acquisition to our financial metrics; our expectations regarding the entry into new LNG agreements and intentions to secure increased exposure to global LNG market prices; and future production and sales expectations, and the drivers thereof. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “continue,” “could,” “estimates,” “expects,” “forecast,” “future,” “guidance,” “intend,” “may,” “outlook,” “plans,” “positioned,” “projects,” “seek,” “should,” “targets,” “will,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, these expectations may not prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

Our overall business strategy is to responsibly deliver competitive corporate level returns, free cash flow and cash returns to shareholders, all of which are sustainable and resilient through long-term commodity price cycles. We expect to achieve our business strategy by adherence to a disciplined reinvestment rate capital allocation framework that limits our capital expenditures relative to our expected cash flow from operations. Keeping our workforce safe, maintaining a strong balance sheet, responsibly meeting global energy demand with a focus on continuously improving environmental performance, serving as a trusted partner to our local communities and maintaining best in-class corporate governance standards are foundational to the execution of our strategy.

We believe we have satisfactory title to our United States and International properties in accordance with standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time that may result in litigation. In the case of undeveloped properties, an investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Our title to properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry. In addition, our interests may be subject to obligations or duties under applicable laws or burdens such as net profits interests, liens related to operating agreements, development obligations or capital commitments under international production sharing contracts or exploration licenses.

At December 31, 2022, 2021 and 2020, Eagle Ford, Bakken and Oklahoma in the United States contained 15% or more of our total proved reserves. Production for these fields along with our production from fields containing less than 15% of our total proved reserves are presented in the table below.


	December 31,
	2022	2021	2020
Net Sales Volumes
Crude oil and condensate (mbbld) (a)
United States
Eagle Ford	57	58	61
Bakken	71	74	79
Oklahoma	12	12	17
Permian	14	13	15
Other U.S.	5	4	5

E.G.	10	11	13


Total	169	172	190
Natural gas liquids (mbbld)
United States
Eagle Ford	15	15	18
Bakken	25	23	14
Oklahoma	17	17	20
Permian	5	5	5
Other U.S.	2	2	2

E.G.	7	7	9


Total	71	69	68
Natural gas (mmcfd)
United States
Eagle Ford	86	97	121
Bakken	87	90	70
Oklahoma	140	147	177
Permian	34	32	41
Other U.S.	16	13	14

E.G.	252	259	330


Total	615	638	753


Total sales volumes (mboed)
United States
Eagle Ford	86	89	99
Bakken	111	112	105
Oklahoma	52	54	66
Permian	25	23	27
Other U.S.	10	8	9

E.G.	59	61	77



Total	343	347	383

Competition exists in all sectors of the oil and gas industry, and we compete with major integrated and independent oil and gas companies, national oil companies, and to a lesser extent, companies that supply alternative sources of energy. We compete, in particular, for the acquisition of oil and natural gas leases and other properties, in the exploration for and development of new reserves, the marketing and delivery of our production into worldwide commodity markets and for the labor and equipment required for exploration and development of those properties. Principal methods of competing include geological, geophysical and engineering research and technology, experience and expertise, economic analysis in connection with portfolio management and safely operating oil and gas producing properties. See Item 1A. Risk Factors for discussion of specific areas in which we compete and related risks.

Our businesses are subject to numerous laws and regulations, including those related to oil and gas exploration and production and to the protection of health, environment and safety. New laws have been enacted or are otherwise being considered and regulations are being adopted by various regulatory agencies on a continuing basis. The costs of compliance with these new laws and regulations cannot be broadly appraised until their implementation becomes more defined. However, the current federal administration has begun implementing policies to increase regulation of oil and gas activity with the express purpose of transitioning the economy to lower-carbon sources of energy consistent with the administration’s focus on climate change. This administration’s climate policies have been wide-ranging and have included both legislative and executive branch action to address climate change and provide incentives to accelerate development of renewable resources.

The current administration has issued a number of executive and temporary orders and policy changes that address broad ranging issues including climate change, oil and gas activities on federal lands, infrastructure and environmental justice. These actions have been followed by a number of related regulatory proposals that are in various stages of the rulemaking process including: more stringent and potentially overlapping regulations of emissions from oil and gas activities, expected further expansion of the definition of Waters of the U.S., increased barriers to access to federal lands for oil and gas development, increased protection for endangered species, more stringent permitting requirements for oil and gas facilities, additional disclosures for climate change risks and implementing regulations for provisions of the Inflation Reduction Act of 2022.

We expect these regulatory changes, if finalized, may increase our administrative costs and affect the issuance of permits and/or agency approvals. If permits and approvals are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities due to these orders or policy changes, we may not be able to conduct our operations as planned. At this time, we do not expect that the proposed or anticipated rulemakings will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. However, the finalized versions of the proposed rules or new rules could have a material adverse impact on our business individually or collectively, depending on the final terms and timing of implementation.

The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety matters. Our Corporate Health, Environment, Safety and Security organization is responsible for ensuring that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team that oversees our response to any major environmental or other emergency incident involving us or any of our properties.

Our business is subject to laws relating to remediation of environmental pollution and the storage, handling and disposal of waste. These laws, and their implementing regulations and other similar state and local laws and rules, can impose certain operational requirements for (i) minimization of pollution, (ii) monitoring, reporting and recordkeeping requirements or (iii) other operational or siting constraints on our business. These controls result in costs to remediate releases of regulated substances, including crude oil and produced water, into the environment, or require costs to remediate third-party sites to which we sent regulated substances for disposal. In some cases, these laws can impose strict liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others (such as prior owners or operators of our assets) or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We have incurred and will continue to incur capital, operating and maintenance and remediation expenditures as a result of environmental laws and regulations.

Concerns about emissions from oil and gas activities including volatile organic compounds, carbon dioxide, methane and other greenhouse gases may affect us and other similarly situated companies operating in the oil and gas industry. As described in more detail below, several regulatory proposals seek to reduce emissions of greenhouse gases. While we cannot fully evaluate potential impacts of such proposed rules until they are finalized, as part of our commitment to environmental stewardship and as required by law, we estimate and publicly report certain greenhouse gas emissions from our operations. We are also working to continuously improve the accuracy and completeness of these estimates. Finally, we have also undertaken initiatives to highlight our commitment to improving environmental performance, including introducing new quantitative goals for the near, medium and long-term time horizon across three core areas of focus: GHG intensity, methane intensity and gas capture. We have added a GHG emissions intensity target to our short-term incentive annual cash bonus scorecard to better reflect these initiatives.

Government entities and other groups have filed lawsuits in several states and other jurisdictions seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operations or cash flow.

In June 2016, the EPA finalized amendments to the New Source Performance Standards (NSPS), known as Subpart OOOOa, focused on achieving additional methane and volatile organic compound reductions from new and modified oil and natural gas production and transmission facilities. On November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (including intermittent vent pneumatic controllers, associated gas and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. On November 15, 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. The EPA is expected to issue a final rule by late 2023. In mid-2021, the State of New Mexico implemented regulations that seek to reduce GHG emissions in the state. In November 2022, BLM proposed a rule requiring additional royalties on methane emissions and regulations designed to limit venting and flaring on public and tribal lands, and a final rule is expected by late 2023.

The EPA finalized a more stringent NAAQS for ozone in October 2015. States that contain any areas designated as non-attainment, and any tribes that chose to do so, were required to complete development of implementation plans. The EPA may in the future designate additional areas, including but not limited to portions of the Permian Basin, as non-attainment, impacting areas in which we operate. In January 2023, the EPA proposed a rule that would lower the annual particulate matter of less than 2.5 microns (PM2.5) NAAQS from the current 12 micrograms per meter cubed (µg/m3) to a level between 9 µg/m3 and 10 µg/m3, and comments are due by March 28, 2023. The implementation of this proposed limit, or the promulgation of a more stringent standard in the future, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with this revised regulation (if finalized), the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.

The federal administration previously included as part of its platform actions that could amount to a de facto ban on hydraulic fracturing on federal lands and the EPA and other federal agencies, including the BLM, have previously made proposals that, if implemented, could either restrict the practice of hydraulic fracturing or subject the process to further regulation (and there is some question as to whether this could extend to tribal lands). Further, state and local-level initiatives may be proposed in regions with substantial shale resources to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used or implement temporary or permanent bans on hydraulic fracturing. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with these initiatives, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.

In 2014, the EPA and the U.S. Army Corps of Engineers (“Corps”) published proposed regulations which expand the scope of surface waters that are regulated under the federal CWA and its various programs known as WOTUS. In 2015, the EPA and the Corps issued a rule defining the scope of the EPA’s and the Corps’ jurisdiction over WOTUS, which never took effect before being replaced by the Navigable Waters Protection Rule (“NWPR”) in 2020. A coalition of states and cities, environmental groups and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA is undergoing a two-phase rulemaking process to redefine WOTUS, which could be impacted by the U.S. Supreme Court’s upcoming decision in Sackett v. EPA, a case regarding the proper test in determining whether wetlands qualify as WOTUS. A final rule, known as “Rule 1”, was announced by the EPA and the Corps in December 2022. The EPA and the Corps are expected to propose a second rule, known as “Rule 2”, further refining Rule 1, by November 2023 and issue a final rule by July 2024.

At Marathon Oil, we believe talent is foundational to delivering on our corporate strategy. We believe it allows us to consistently deliver on our framework for success, aimed at achieving sustainable free cash flow, meaningful return of capital to our shareholders and differentiated execution underpinned by a strong balance sheet, ESG excellence and our multi-basin portfolio. We believe intentional human capital management strategies enable us to attract, develop, retain and reward our dedicated employees. We believe in creating a safe, clean and ethical environment where employees feel empowered to make a difference in support of our business objectives and strategies. Our Vice President of Human Resources has leadership accountability for our workforce management policies and programs and reports directly to our CEO. She reviews quarterly talent data with our Executive Committee to assess the talent landscape and ensure measurement and accountability for human capital outcomes. Our Board provides oversight to our human capital management strategies as an integral part of our overall Enterprise Risk Management process. Due to the importance of our workforce capabilities, the Board receives updates on our human capital management measures as topical matters arise, such as talent as an enterprise risk, employee engagement, diversity and inclusion, succession, Health, Environment and Safety (HES) and corporate social responsibility. Please visit marathonoil.com/sustainability for information on all dimensions of our corporate social responsibility. The information contained on or accessible through our website is not incorporated by reference herein or otherwise made a part of this Annual Report on Form 10-K or any of our other filings with the SEC.

We believe in fostering an inclusive culture to ensure the strength and resilience of our business. We are committed to creating an environment where everyone can achieve their full potential and respectful relationships are core to our culture. Our Code of Business Conduct, which applies to our directors, officers, employees and other parties when they are acting on behalf of Marathon Oil, reinforces our long-standing commitment to high ethical standards and summarizes the fundamental importance of acting with integrity. It includes specific sections on Diversity, Equity and Inclusion (“DEI”), as well as Mutual Respect. These sections include an emphasis on fostering an inclusive work environment and making hiring, promotion and disciplinary decisions based on relevant qualifications, merit, performance and similar job-related factors. We believe our diversity of people, experiences and ideas provides us with a business advantage. We are committed to fair and nondiscriminatory hiring and to celebrating the diversity of our workforce.

For the U.S. workforce, our average tenure for full-time employees as of December 31, 2022 was 8 years, with 31% of our full-time population having 10 or more years of experience. Women and people of color each accounted for 32% of our U.S. full-time workforce. We encourage diversity, equity and inclusion (DEI) and cultivate our collaborative team environment by making training courses on diversity and inclusive leadership available to all employees. We support Employee Resource Groups (“ERGs”) to promote diverse perspectives, encourage networking and allow continuous development activities. We added two new ERGs in 2022 and expanded voluntary enterprise-wide DEI training to continue to foster our One Team culture. We also continued to support the mental well-being of our employees by focusing on educating and empowering our employees to talk about mental wellness and promoting the resources available to them, including new benefit offerings in 2022.

We believe safety is a core value and engrained in all aspects of our business. We uphold our safety and health culture by attracting, developing and retaining individuals and partners who share our commitment to operational excellence. Marathon Oil’s leadership establishes clear expectations to all personnel to comply with internal and external safety and health requirements. Furthermore, our HES values are embedded within our culture and the support we provide to our employees. We provide and require job specific HES training for our employees and safety-sensitive contractors as part of our Responsible Operations Management Systems (“ROMS”), which is a comprehensive operations integrity management system. This training includes stop the job authority extended to all employees and contractors in the event of a potential safety risk or environmental impact.

Our values to collaborate, take ownership, be bold and deliver results enable us to excel, but that’s only possible if our workforce is safe. We actively look out for each other, maintain a safe work environment, continuously improve our procedures and train our workforce. Marathon Oil utilizes ROMS to manage risk and strives for a safe, healthy and secure workplace where all those involved can work free of injury and illness. Our Total Recordable Injury Rate (“TRIR”) is just one of the metrics we use to measure our success in providing a safe working environment and is linked directly to compensation outcomes. Marathon strives to only partner with contractors who share our same commitment to safety and environmental impact. We carefully evaluate contractors through a rigorous supply chain process to verify they possess all necessary safety and health programs to execute work in a manner that meets our expectations.

We attract and retain talent by offering benefit programs that are competitive and comprehensive. These programs create flexibility that allows employees to develop a meaningful career and overall well-being for themselves and their families. In August 2022, we made the commitment to fund employee premiums for health plans through 2023 to help support them through ongoing inflationary pressures. Our goal is to support employees with benefit programs that are consistent with our company's vision and strategies. We align the value of the benefit programs to the local markets where we compete for talent, along with the broader oil and gas industry. We believe effective communication around our benefit programs helps ensure we understand employees' perceptions and values around our benefits and that our employees understand the breadth and value of the benefits provided.

Our success is based on financial performance and operational results, and we believe that our compensation program is an important driver of that success. The primary objectives of our programs are to pay for performance, encourage long-term stockholder value and pay competitively. To accomplish this, our compensation program is designed to reward employees for their performance and motivate them to continue to perform at a high level through both absolute feedback and relative performance assessment. The annual cash bonus is our short-term incentive for eligible employees, which reinforces both corporate and individual annual performance and prioritizes both financial and operational metrics. In 2022, in addition to the annual cash bonus, we provided a one-time cash payment to all eligible full-time employees to recognize and reward their invaluable contribution to our operational and financial success, which included significantly exceeding our commitment to return capital to shareholders through share repurchases and dividends paid. Eligible employees may also receive long-term incentives in the form of restricted stock awards that vest over multiple years to support retention and aligns employee interests with those of our stockholders, by driving value at the enterprise level. We provide market-competitive pay levels to attract and retain the best talent. We regularly benchmark each component of our pay program, including our benefit programs against our peers and a broader subset of the oil and gas industry, to ensure we remain competitive. See the “Compensation Discussion and Analysis” section of our Annual Proxy for information on our Executive Officers.

We review talent across the enterprise, measuring both technical and leadership capabilities. We leverage these talent assessments to identify critical skill gaps, guide critical skills training and ensure the effective deployment of talent. Our talent planning processes are aligned and consistent across the organization to ensure top talent occupies our most critical roles. Our succession process is designed to ensure we have identified the experiences and exposures needed to prepare employees for success in future senior leadership roles. We utilize an employee mentoring program, which focuses on increasing communication, connection and trust to advance our company’s culture. We also continued our Board mentoring program, which pairs senior leaders with directors.

Mr. Tillman was appointed by the Board of Directors as chairman of the board effective February 1, 2019. In August 2013, he was appointed as president and chief executive officer. Prior to this appointment, Mr. Tillman served as vice president of engineering for ExxonMobil Development Company (a project design and execution company), where he was responsible for all global engineering staff engaged in major project concept selection, front-end design and engineering. Between 2007 and 2010, Mr. Tillman served as North Sea production manager and lead country manager for subsidiaries of ExxonMobil in Stavanger, Norway. Mr. Tillman began his career in the oil and gas industry at Exxon Corporation in 1989 as a research engineer and has extensive operations management and leadership experience.

Mr. Whitehead was appointed executive vice president and chief financial officer in March 2017. Prior to this appointment, Mr. Whitehead served as executive vice president and chief financial officer of both EP Energy Corp. and EP Energy LLC (oil and natural gas producer) since May 2012. Between 2009 and 2012, Mr. Whitehead served as senior vice president of strategy and enterprise business development and a member of El Paso Corporation’s executive committee. He joined El Paso Exploration & Production Company as senior vice president and chief financial officer in 2006. Before joining El Paso, Mr. Whitehead was vice president, controller and chief accounting officer of Burlington Resources Inc. (oil and natural gas producer), and formerly senior vice president and CFO of Burlington Resources Canada.

Mr. Wagner was appointed executive vice president of corporate development and strategy in November 2017 after having served as senior vice president of corporate development and strategy since March 2017, vice president of corporate development and interim chief financial officer since August 2016 and vice president of corporate development since April 2014. Prior to this appointment, he served as senior vice president, western business unit, for QR Energy LP (an oil and natural gas producer) and the affiliated Quantum Resources Management, which he joined in early 2012 as vice president, exploitation. Prior to that, Mr. Wagner was managing director in Houston for Scotia Waterous, the oil and gas arm of Scotiabank (an international banking services provider), from 2010 to 2012. Before joining Scotia, Mr. Wagner was vice president, Gulf of Mexico, for Devon Energy Corp. (an oil and natural gas producer), having joined Devon in 2003 as manager, international exploitation.

Mr. Henderson was appointed executive vice president, operations in March 2021, after having served as senior vice president, operations since May 2020, and as vice president of Regional Plays North since October 2017. Prior to that he held successive regional vice president roles since 2013 and managed operations in Oklahoma, North Dakota and Wyoming. Prior to his work in the resource plays, Mr. Henderson was development manager for international production operations in Equatorial Guinea and has been involved in a number of Marathon Oil’s major projects in Equatorial Guinea, Norway and the Gulf of Mexico over the course of his career. Before joining Marathon Oil in 2004, he was employed by ExxonMobil, where he served in a number of operations and project management roles of increasing responsibility.

Ms. Warnica was appointed executive vice president, general counsel in March 2022 after having served as senior vice president, general counsel since January 2021. Ms. Warnica was appointed secretary in March 2021. Prior to joining Marathon Oil, she was executive vice president, general counsel, chief compliance officer and secretary at Alta Mesa Resources, Inc. (an exploration and production and midstream company), since 2018. Prior to Alta Mesa, Ms. Warnica served in several positions in the Marathon Oil legal department from 2016 to 2018, including assistant general counsel and assistant secretary. Prior to Marathon Oil, Ms. Warnica served as assistant general counsel and assistant secretary at Freeport-McMoRan Oil & Gas (formerly Plains Exploration and Production Company, an oil and gas production company). She started her career at Andrews Kurth LLP.

Our website is www.marathonoil.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and filings with the SEC are available free of charge on our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. Information contained on our website is not incorporated into this Annual Report on Form 10-K or our other securities filings. Our filings are also available in hard copy, free of charge, by contacting us at 990 Town and Country Boulevard, Houston, Texas 77024-2217, Attention: Investor Relations Office, telephone: (713) 629-6600. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

The proved reserve information included in this Annual Report on Form 10-K has been derived from engineering and geoscience estimates. Estimates of crude oil and condensate, NGLs and natural gas were prepared, in accordance with SEC regulations, by teams of reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group. Reserves were valued based on SEC pricing for the periods ended December 31, 2022, 2021 and 2020, as well as other conditions in existence at those dates. The table below provides the 2022 SEC pricing for certain benchmark prices:


	2022 SEC Pricing
WTI crude oil (per bbl)	$	93.67
Henry Hub natural gas (per mmbtu)	$	6.36
Brent crude oil (per bbl)	$	100.25
Mont Belvieu NGLs (per bbl)	$	36.59

The marketability of our production depends in part on the availability, proximity and capacity of gathering and transportation pipeline facilities, rail cars, trucks and vessels. These facilities and equipment may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our crude oil and condensate, NGLs and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production. A pipeline shutdown could also have an impact on safety because it would require the use of additional trucks, rail cars and personnel. In addition, both the cost and availability of pipelines, rail cars, trucks or vessels to transport our production could be adversely impacted by new state or federal regulations relating to transportation of crude oil. Any significant change in market, regulatory or other conditions affecting our access to, or the availability of, these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.

We typically seek the acquisition of crude oil and natural gas properties and leases. For example, in December 2022, we completed the acquisition of the Eagle Ford assets of Ensign Natural Resources for total cash consideration of $3.0 billion. Although we perform reviews of properties to be acquired in a manner that we believe is diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, including title problems, nor may they permit us to become sufficiently familiar with the properties in order to fully assess possible deficiencies and potential problems. Properties and leases that we acquire may be subject to prior unregistered agreements, or transfers which have not been recorded or detected through our due diligence searches. If title to property associated with our projects is challenged, we may have to expend funds defending any such claims and our ownership interest therein may be detrimentally affected if we lose. Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements. Moreover, there are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and natural gas (as previously discussed), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

We are, and may in the future become, subject to various laws and regulations that apply to operators and other parties operating within the boundaries of Native American reservations in the United States. These laws and regulations may result in the imposition of certain fees, taxes, environmental standards, lease conditions or requirements to employ specified contractors or service providers. Any one of these requirements, or any delay in obtaining, or inability to obtain, the approvals or permits necessary to operate within the boundaries of Native American tribal lands, could adversely impact the Company’s operations and ability to explore and develop new and existing properties. Additionally, from time to time, disputes may arise between state or federal governments and Native American tribes regarding title to lands within the United States or questions of sovereignty between the states and Native American tribes. For example, the State of North Dakota and three Indian tribes (the “Three Affiliated Tribes”) represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River (the “Disputed Land”) from which we currently produce. The United States Department of the Interior (“DOI”) has addressed the United States’ position with respect to this dispute several times over the past five years with conflicting opinions. Most recently, on February 4, 2022, the DOI issued an opinion (“M-Opinion”) concluding the DOI’s position that the Disputed Land is held in trust for the Three Affiliated Tribes. While the M-Opinion is binding on all agencies within the DOI, it is not legally binding on third parties, including Marathon Oil, or a court. Depending on the ultimate outcome of this title dispute, the Three Affiliated Tribes could challenge the validity of certain of our leases relating to a portion of the disputed land, and if such challenge were successful it could result in operational delays and additional costs, which could have a material and adverse effect on our business and results of operations. In addition, the process of addressing such claim or dispute, regardless of the outcome, could be expensive and time consuming and could result in delays which could have a material and adverse effect on our business, financial condition and results of operations.

The oil and gas industry is highly competitive, and many competitors, including major integrated and independent oil and gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. We also compete with these companies for equipment and personnel, including petroleum engineers, geologists, geophysicists and other specialists, required to develop and operate those properties and in the marketing of crude oil and condensate, NGLs and natural gas to end-users. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties. They may also be able to use their greater resources to attract and retain experienced personnel.

Policy and Legal Risks. Policy risks include actions that seek to lessen activities that contribute to adverse effects of climate change or to promote adaptation to climate change, such as the enactment of climate change-related regulations, policies and initiatives addressing alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures or responsible energy development, among other measures. Policy actions also may include restrictions or bans on oil and gas activities, like the January 2021 Presidential and Secretarial orders, and the potential banning of hydraulic fracturing, which could lead to write-downs or impairments of our assets. Legal risks include potential lawsuits claiming, among other things, failure to mitigate impacts of climate change, failure to adapt to climate change and the insufficiency of disclosure around material financial risks. For instance, government entities and other groups have filed lawsuits in several states seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions and other alleged harm attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. The increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business.

Market Risks. Markets could be affected by climate change through shifts in supply and demand for certain commodities, including oil and gas and other products dependent on oil and gas. Lower demand for our oil and gas production, or lower demand for products that use oil and gas as fuel sources or increased demand for lower-emission or more efficient products and services, could result in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to industries and alternative energy industries that may be, or be perceived to be, less carbon-intensive. In addition, certain investment advisers, banks and sovereign wealth, pension and endowment funds recently have been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in the extraction, production and sale of oil and gas. Some banks and asset managers have made climate-related pledges for various initiatives, such as stopping the financing of Arctic drilling and coal companies. These initiatives by activists and banks could interfere with our business activities, operations and ability to access capital. Institutional lenders who provide financing to energy companies such as ours have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding.

Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, winter storms, droughts or floods) or longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts such as supply or distribution chain disruption and also could include changes in water or other raw material availability, sourcing, pricing and quality, which could impact drilling and completions operations. These physical risks could adversely affect or delay demand for oil or natural gas, cause increased costs, production disruptions and lower revenues and substantially increase the cost or limit the availability of insurance.

The rate of production from crude oil and condensate, NGLs and natural gas properties generally decline as reserves are depleted. Except to the extent we acquire interests in additional properties containing proved reserves, conduct successful exploration and development activities, or, through engineering studies, optimize production performance or identify additional reservoirs not currently producing or secondary recovery reserves, our proved reserves may decline materially as crude oil and condensate, NGLs and natural gas are produced. Accordingly, to the extent we are not successful in replacing the crude oil and condensate, NGLs and natural gas we produce, our future revenues may decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:

We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, or transportation of crude oil and condensate, NGLs and natural gas, with partners, co-working interest owners and other counterparties in order to share risks associated with those operations. In addition, we market our products to a variety of purchasers. If commodity prices decrease, some of our counterparties may experience liquidity problems and may not be able to meet their financial and other obligations to us. The inability of our joint venture partners or co-working interest owners to fund their portion of the costs under our joint venture agreements and joint operating agreements, or the nonperformance by purchasers, contractors or other counterparties of their obligations to us, could negatively impact our operating results and cash flows.

We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for general corporate or other purposes. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service our debt depends on future performance. General economic conditions, crude oil and condensate, NGLs and natural gas prices, inflation, interest rates and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the principal and interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for a discussion of debt obligations.

A downgrade of our credit ratings or other influences, including third-party groups promoting the divestment of fossil fuel equities or pressuring financial services companies to limit or curtail activities with fossil fuel companies, could negatively impact our cost of capital and our ability to access the capital markets, increase the interest rate and fees we pay on our Credit Facility and Term Loan Facility, and may limit or reduce credit lines with our bank counterparties. We receive credit ratings on our debt obligations from the major credit rating agencies in the United States. Due to the volatility in worldwide crude oil, NGL and natural gas prices in recent years, credit rating agencies review companies in the energy industry periodically, including us. At December 31, 2022, our corporate credit ratings were: Standard & Poor’s Global Ratings Services BBB- (stable); Fitch Ratings BBB- (positive); and Moody’s Investor Services, Inc. Baa3 (stable). Each credit rating should be evaluated independently and is not a recommendation to buy, sell or hold securities, and may be subject to revision or withdrawal by the assigning rating organization from time to time. The credit rating process is contingent upon a number of factors, many of which are beyond our control. We could also be required to post letters of credit or other forms of collateral for certain contractual obligations, which could increase our costs and decrease our liquidity or letter of credit capacity under our Credit Facility. Limitations on our ability to access capital could adversely impact the level of our capital spending budget, our ability to manage our debt maturities, or our flexibility to react to changing economic and business conditions.

Global commodity prices are volatile. In order to mitigate commodity price volatility and increase the predictability of cash flows related to the marketing of our crude oil, NGLs and natural gas, we, from time to time, enter into crude oil, NGL and natural gas hedging arrangements with respect to a portion of our expected production. While hedging arrangements are intended to mitigate commodity price volatility, we may be prevented from fully realizing the benefits of price increases above the price levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Additionally, states in which we operate are considering proposals to address climate change or increase regulations of the oil and gas industry or impose additional regulations based on questions of sovereignty between the states and Native American tribes. We have incurred and may continue to incur capital, operating and maintenance and remediation expenditures as a result of these laws, regulations and other requirements or initiatives that are being considered or otherwise implemented. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results could be adversely affected. The specific impact of these laws, regulations and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations and other requirements could result in civil penalties or criminal fines and other enforcement actions against us. For example, we have received Notices of Violation from the EPA related to allegations of violations of the Clean Air Act relating to our operations on the Fort Berthold Indian Reservation between 2015 and 2019. We are actively negotiating a draft consent decree with the EPA and Department of Justice containing certain proposed injunctive terms relating to this enforcement action. The enforcement action will likely include monetary sanctions and implementation of both environmental mitigation projects and injunctive terms, which would increase both our development costs and operating costs. Through the date of this filing, there exists substantial uncertainty as to the ultimate result of this matter and it is reasonably possible the result could be materially different from our accrual.

The Biden administration has already taken steps to address climate change, and we expect actions like these to continue, including additional orders, laws or regulations that could affect our operations. Our operations result in greenhouse gas emissions. Currently, various legislative or regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in the U.S. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius (the “Paris Agreement”). The Paris Agreement requires signatory countries to set voluntary targets to reduce domestic greenhouse gas emissions. In November 2020, the U.S. withdrew from the Paris Agreement. However, in February 2021, President Biden recommitted the U.S. to the Paris Agreement along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the United Nations Climate Change Conference (“COP26”), over 100 countries have joined the pledge. Most recently, at the 27th Conference of Parties (“COP27”), President Biden announced the EPA’s proposed standards to reduce methane emissions from existing oil and gas sources and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. In addition, the $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives aimed at climate resilience, enhanced response and preparation for extreme weather events and clean energy and transportation investments. The IRA also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. In addition, a number of U.S. state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives to encourage the use of renewable energy or alternative low-carbon fuels, and cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties. New legislation, regulations or international agreements in the future could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and condensate, NGLs, and natural gas and create delays in our obtaining air pollution permits for new or modified facilities.

Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting, operational, technology and financial compliance costs, make some activities more difficult, time-consuming and costly and place strain on our personnel, systems and resources.

Hydraulic fracturing is a commonly used process that involves injecting water, sand and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Our business uses this technique extensively throughout our U.S. operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Various state and local-level initiatives in regions with substantial shale resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and condensate, NGLs and natural gas, including from the shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells.

The production of oil and gas inherently involves the generation of produced water and oil and gas waste. State and federal regulatory agencies have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. When caused by human activity, such events are called induced seismicity. Marathon operates produced water injection wells and contracts for disposal of oil and gas waste in injection wells operated by third parties. Additionally, Marathon uses hydraulic fracturing techniques throughout its U.S. operations.

The legal requirements related to the disposal of produced water by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near injection disposal wells that are used for the disposal by injection of produced water resulting from oil and natural gas activities. In 2016, the United States Geological Survey identified New Mexico, Oklahoma and Texas as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting and operating of produced water disposal wells. For example, in Texas, the Railroad Commission adopted rules in 2014 governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and natural gas in order to address induced seismicity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Another example includes the recent Seismic Event Mitigation Plan and Protocol announced by the New Mexico Oil Conservation Division in 2021, which requires monitoring and the potential curtailments or shut-ins of salt water disposal wells located within specified distances of certain seismic events. States may issue new orders or implement policies to temporarily shut down or to curtail the injection volumes of existing wells in the vicinity of seismic events. Legislative, regulatory and policy initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations.

Changes in the U.S. or global political and economic environment or any U.S. or global hostility or the occurrence or threat of future terrorist attacks, or other armed conflict, could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for crude oil and condensate, NGLs and natural gas. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate. These risks could also cause damage to, or the inability to access, production facilities or other operating assets and could limit our service and equipment providers ability to deliver items necessary for us to conduct our operations.

Actions of governments through tax legislation or interpretations of tax law, and other changes in law, executive order and commercial restrictions could reduce our operating profitability, both in the U.S. and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries and will continue to do so in the future. Changes in U.S. or foreign laws could also adversely affect our results, including new regulations resulting in higher costs to comply with regulations and higher costs to transport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.

Throughout 2022, we experienced significant increases in the costs of certain materials, including steel, sand and fuel, as a result of availability constraints, supply chain disruption, increased demand, labor shortages associated with a fully employed US labor force, inflation and other factors. Though we incorporated inflationary factors into our 2022 business plan, inflation outpaced those original assumptions and, while we have incorporated inflationary factors into our 2023 business plan, inflation may outpace those assumptions. These challenges are due in large measure to increased demand for oil and gas production driven by the continued economic recovery from the COVID-19 pandemic and more broadly, systemic underinvestment in global oil and gas development. These supply and demand fundamentals have been further aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing conflict between Russia and Ukraine. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and may continue to experience inflationary pressure on our cost structure. These supply chain constraints and inflationary pressures may continue to adversely impact our cost of operations and if we are unable to manage our global supply chain, it may impact our ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

We are subject to income- and non-income-based taxes in the United States under federal, state, and local jurisdictions and in the foreign jurisdictions in which we operate. Tax laws, regulations and administrative practices in various jurisdictions may be subject to significant change, with or without advance notice, due to economic, political and other conditions, and significant judgment is required in evaluating and estimating our provision and accruals for these taxes. Our tax liabilities could be affected by numerous factors, such as changes in tax, accounting and other laws, regulations, administrative practices, principles and interpretations, the mix and level of earnings in a given taxing jurisdiction or our ownership or capital structure. For example, on August 16, 2022, the United States enacted the IRA, which is highly complex, subject to interpretation, and contains significant changes to U.S. tax law including, but not limited to, a 15% corporate book minimum tax and a 1% excise tax on stock repurchases. The U.S. Department of the Treasury and the IRS are expected to release further regulations and interpretive guidance implementing the legislation contained in the IRA, but the details and timing of such regulations are subject to uncertainty at this time. The tax provisions of the IRA which may apply to us are generally effective in 2023 or later and therefore tax impacts to us in 2022 were immaterial. However, it is possible that the enactment of changes in the U.S. corporate tax system, including in connection with the IRA, could have a material effect on our consolidated cash taxes in the future.

For example, the novel coronavirus global pandemic, known as COVID-19, had a material adverse impact on our business, financial condition and results of operations in 2020. The early effects of COVID-19 included a substantial decline in demand for crude oil, condensate, NGLs, natural gas and other petroleum hydrocarbons, along with a corresponding deterioration in prices. While demand for crude oil, condensate, NGLs, natural gas and other petroleum hydrocarbons significantly recovered as the COVID-19 pandemic evolved, we are unable to predict the future impact of COVID-19 (including the emergence, contagiousness and threat of new and different strains), or a widespread outbreak of another contagious disease, on overall economic activity and the demand for, and pricing of, our products. COVID-19, or a widespread outbreak of another contagious disease, could have a negative impact on our operations; impact the ability of our counterparties to perform their obligations; result in voluntary and involuntary curtailments, delays or cancellations of certain drilling activities; impair the quantity or value of our reserves; result in transportation and storage capacity constraints; cause shortages of key personnel, including employees, contractors and subcontractors; interrupt global supply chains; increase impairments and associated charges to our earnings; impact our cash on hand, uses of cash and cause a decrease to our financial flexibility and liquidity. In addition, the risks associated with COVID-19 impacted, and COVID-19, or a widespread outbreak of another contagious disease, may in the future impact our workforce and the way we meet our business objectives, and such impact may be material. The extent to which the ongoing COVID-19 pandemic will impact our business and our financial results will depend on future developments, which are highly uncertain and cannot be predicted.

Our business, like other companies in the oil and gas industry, has become increasingly dependent on digital technologies, including technologies that are managed by third-party service providers or other providers of goods or services to our industry on whom we directly or indirectly rely to help us collect, host or process information. Such technologies are integrated into our business operations and used as a part of our production and distribution systems in the U.S. and abroad, including those systems used to transport production to market, to enable communications and to provide a host of other support services for our business. Accordingly, our use of the internet and other public networks for communications, services and storage, including “cloud” computing, exposes us and our users to cybersecurity risks.

There is no guarantee that our security measures will provide absolute security. We may not be able to anticipate, detect or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using techniques designed to circumvent controls and avoid detection. We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in the unauthorized access to our information systems or data, the data of our customers and our employees or significant disruption to our business. These attacks could adversely impact our business operations, our revenue and profits, our ability to comply with legal, contractual and regulatory requirements, our reputation and goodwill, as well as result in legal risk, enforcement actions and litigation. Our information systems and related infrastructure have experienced attempted and actual instances of unauthorized access in the past, but we have not suffered any losses or breaches which had a material effect on our business, operations or reputation relating to such attacks; however, there is no assurance that we will not suffer such losses or breaches in the future.

From time to time, political and public sentiment with respect to, or impacts by, the oil and gas industry may result in adverse press coverage and other adverse public statements affecting our business. Additionally, though we believe we can achieve our voluntary company targets and goals, any failure to realize or perception of failure to realize voluntary targets or long-term goals, including GHG emissions targets and other environmental objectives, could lead to adverse press coverage and other adverse public statements affecting Marathon Oil. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims.

Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Various hazards have adversely affected us in the past, and damages resulting from a catastrophic occurrence in the future involving us or any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially large claims or in our being assessed potentially substantial fines by governmental authorities. We maintain insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we have maintained insurance coverage for physical damage including at times resulting business interruption to our major onshore and offshore facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for our insurance policies will change over time and could escalate. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, contract disputes, title disputes, royalty disputes or any other laws or regulations that apply to our operations. In some cases the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.

For instance, government entities and other groups have filed lawsuits in several states seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions and other alleged harm attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. Additionally, Marathon Oil has been named in various lawsuits, which could include class actions, alleging royalty underpayments in our domestic operations. We intend to vigorously defend ourselves against such claims. Although we have accrued for potential liabilities associated with these lawsuits, those accruals are based on currently available information and involve elements of judgment and significant uncertainties. Accordingly, actual losses may exceed our accruals or we could be required to accrue additional amounts in the future and these amounts could be material. The ultimate outcome and impact to us cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.

Government entities have filed lawsuits in several states seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions and other alleged harm attributable to those fuels. The lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various theories. Marathon Oil has been named as a defendant in several of these lawsuits, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operations or cash flow.

We received Notices of Violation (“NOV”)’s from the EPA related to allegations of violations of the Clean Air Act relating to our operations on the Ford Berthold Indian Reservation between 2015 and 2019. We continue to actively negotiate a draft consent decree with the EPA and Department of Justice containing certain proposed injunctive terms relating to this enforcement action. The resolution of the enforcement action will likely include monetary sanctions and implementation of both environmental mitigation projects and injunctive terms, which would increase both our development costs and operating costs. We do not believe resolution of this matter will have a material adverse effect on our business or operations. We maintain an accrual for estimated future costs related to this matter regarding actions required to retrofit or replace existing equipment, which we expect to incur over multiple years. Our accrual does not include possible monetary sanctions or costs associated with mitigation projects as we are unable to estimate those amounts. Through the date of this filing, there exists substantial uncertainty as to the ultimate result of this matter and it is reasonably possible the result could be materially different from our accrual.

Issuer Purchases of Equity Securities – The following table provides information about purchases by Marathon Oil, during the quarter ended December 31, 2022, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934. As of December 31, 2022, we have approximately $2.5 billion of authorization remaining under the share repurchase program.


Period	Total Number of Shares Purchased(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)
10/01/2022 - 10/31/2022	7,691,855	$	27.30	7,691,855	$	715,754,361
11/01/2022 - 11/30/2022	2,247,685	$	31.14	2,247,685	$	2,470,000,107
12/01/2022 - 12/31/2022	—	$	—	—	$	2,470,000,107
Total	9,939,540	$	28.17	9,939,540

We are an independent exploration and production company, focused on U.S. resource plays: Eagle Ford in Texas, Bakken in North Dakota, STACK and SCOOP in Oklahoma and Permian in New Mexico and Texas. Our U.S. assets are complemented by our international operations in E.G. Our overall business strategy is to responsibly deliver competitive corporate return levels, free cash flow and cash returns to shareholders, all of which are sustainable and resilient through long-term commodity price cycles. We expect to achieve our business strategy by adherence to a disciplined reinvestment rate capital allocation framework that limits our capital expenditures relative to our expected cash flow from operations. Keeping our workforce safe, maintaining a strong balance sheet, responsibly meeting global energy demand with a focus on continuously improving environmental performance, serving as a trusted partner in our local communities and maintaining best in-class corporate governance standards are foundational to the execution of our strategy.

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, redemption of our debt, payment of dividends and funding of share repurchases. Following the initial COVID outbreak in 2020, commodity prices steadily increased due to rising oil demand as global economic activity recovered. However, more recently in 2022, commodity prices have experienced significant volatility due to geopolitical events, including Russia’s invasion of Ukraine, and demand impacts tied to macroeconomic conditions from global inflation. Price volatility was also exacerbated by ongoing OPEC+ petroleum supply limitations, COVID related impacts, strategic petroleum reserve releases and economic sanctions involving producer countries. We continue to expect commodity price volatility given the complex global dynamics of supply and demand that exist in the market. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition – Critical Accounting Estimates for further discussion on how volatility in commodity prices could impact us.

The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for 2022, 2021 and 2020.


	2022		Increase (Decrease)		2021		Increase (Decrease)		2020
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)	$	95.58	43	%	$	66.88	86	%	$	35.93
Natural gas liquids (per bbl)(c)	34.55		20	%	28.89		156	%	11.28
Natural gas (per mcf)(d)	6.11		34	%	4.57		158	%	1.77
Benchmarks
WTI crude oil average of daily prices (per bbl)	$	94.33	38	%	$	68.11	73	%	$	39.34
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	97.74		41	%	69.25		73	%	39.95

Mont Belvieu NGLs (per bbl)(e)	35.78		23	%	29.17		99	%	14.69
Henry Hub natural gas settlement date average (per mmbtu)	6.64		73	%	3.84		85	%	2.08

Natural gas – Dry natural gas, processed by Alba Plant LLC on behalf of the Alba Unit Parties, is sold by the Alba field to EG LNG and AMPCO at fixed-price contracts resulting in realized prices not tracking market price. The gas sales contracts between Alba Unit and EG LNG and AMPCO expire on December 31, 2023 and in 2026, respectively. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO. EG LNG sells LNG on a market-based contract and AMPCO markets methanol at market prices. We are progressing new LNG agreements expected to be effective on January 1, 2024, and our intention is to secure increased exposure to global LNG market prices. Alba Plant LLC and EG LNG process third-party gas from the Alen field under a combination of a tolling and a market linked profit-sharing arrangement, the benefits of which are included in our respective share of income from equity method investees. This profit-sharing arrangement provides exposure to global LNG market prices.

The following table presents sources and uses of cash and cash equivalents for 2022 and 2021:


	Year Ended December 31,
(In millions)	2022		2021
Sources of cash and cash equivalents
Net cash provided by operating activities	$	5,428	$	3,239
Borrowings	1,500		—
Proceeds from revolving credit facility	450		—

Equity method investments - return of capital	12		61
Other	23		23
Total sources of cash and cash equivalents	$	7,413	$	3,323
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(1,450)	$	(1,046)

Acquisitions, net of cash acquired	(3,177)		(47)
Shares repurchased under buyback programs	(2,754)		(724)
Debt repayments	(35)		(1,400)
Debt extinguishment costs	—		(117)
Dividends paid	(220)		(141)
Purchases of shares for tax withholding obligations	(22)		(10)
Other	(1)		—
Total uses of cash and cash equivalents	$	(7,659)	$	(3,485)

On November 2, 2022, we executed a definitive purchase agreement to acquire the assets and certain related liabilities of Ensign Natural Resources in the Eagle Ford resource play in Texas. The transaction was closed on December 27, 2022, for cash consideration of $3.0 billion, which was subject to customary closing adjustments. We funded the acquisition using a combination of cash on hand and borrowings under our Term Loan Facility and Revolving Credit Facility. We believe the transaction will be accretive to our financial metrics while increasing our scale in the Eagle Ford by adding high working interest acreage to our inventory portfolio that is located adjacent to our existing position. In addition, during the fourth quarter of 2022, we increased our ownership interest in operated Eagle Ford resource play acreage for cash consideration of approximately $135 million. See Item 8. Financial Statements and Supplementary Data – Note 4 to the consolidated financial statements for further information related to our 2022 acquisitions.

Our working capital requirements are supported by our cash and cash equivalents and our Revolving Credit Facility. We may draw on our Revolving Credit Facility to meet short-term cash requirements or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, defined benefit plan contributions, repayment of debt maturities, dividends and other amounts that may ultimately be paid in connection with contingencies. See Item 8. Financial Statements and Supplementary Data – Note 25 to the consolidated financial statements for further discussion of how our commitments and contingencies could affect our available liquidity. General economic conditions, commodity prices and financial, business and other factors could affect our operations and our ability to access the capital markets.

We have incurred and will continue to incur capital, operating and maintenance and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil and condensate, NGLs and natural gas reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties are used for testing impairment and the expected future taxable income available to realize deferred tax assets, also in part, rely on estimates of quantities of net reserves. Refer to the applicable sections below for further discussion of these accounting estimates.

The estimation of quantities of net reserves is a highly technical process performed by petroleum engineers and geoscientists for crude oil and condensate, NGLs and natural gas, which is based upon several underlying assumptions. The reserve estimates may change as additional information becomes available and as contractual, operational, economic and political conditions change. We evaluate our reserves using drilling results, reservoir performance, subsurface interpretation and future plans to develop acreage. Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves. As per SEC requirements, proved undeveloped reserve volumes are limited to activity in the 5-year plan and wells that will be developed within 5 years of initial booking. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity and future development costs, production history and continual reassessment of the viability of future production volumes under varying economic conditions.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. If applicable, any excess of the purchase price over the fair value is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment. The most significant assumptions relate to the estimated fair values allocated to proved and unproved liquid hydrocarbon and natural gas properties. Estimated fair values assigned to assets acquired can have a significant effect on our results of operations in the future. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party valuation experts for assistance, including the 2022 Ensign acquisition.

•Future crude oil and condensate, NGLs and natural gas realized prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. There has been significant volatility in crude oil and condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Part I. Item 1A. Risk Factors for further discussion on commodity prices.

Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of an impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value.

We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset by lower costs.

•Estimated quantities of feedstock condensate, NGLs and natural gas processed by our investees. There are two primary sets of inputs used to estimate feedstock volumes processed by our investees. The first input involves hydrocarbons produced from our Alba field. Our equity method investees currently process hydrocarbons from our Alba field, which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from our Alba field are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. The second input involves our estimate of future third-party gas to be processed by our investees. Our investees have capacity to process hydrocarbons from sources other than our Alba field. In 2021, the existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production facility began processing natural gas produced from the third party-owned Alen Unit. Estimated natural gas volumes processed from the Alen Unit are based on forecasts received from the operator of the Alen Unit.

Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which historically only International included goodwill. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test; macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not that the fair value of the International reporting unit is less than its carrying amount, a quantitative goodwill test is performed. The quantitative goodwill test is performed using a combination of market and income approaches. The market approach references observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value and valuation multiples of us and our peers from the investor analyst community. The income approach utilizes discounted cash flows, which are based on forecasted assumptions. Key assumptions to the income approach are the same as those described above regarding our impairment assessment of long-lived assets and are consistent with those that management uses to make business decisions.

We have recorded deferred tax assets and liabilities, measured at enacted tax rates, for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. In accordance with U.S. GAAP, we routinely assess the realizability of our deferred tax assets and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years, as well as the forecasts of future loss in the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on objectivity.

We base our future taxable income estimates on projected financial information which we believe to be reasonably likely to occur. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes. Future operating conditions can be affected by numerous factors, including (i) future crude oil and condensate, NGLs and natural gas prices, (ii) estimated quantities of crude oil and condensate, NGLs and natural gas, (iii) expected timing of production, and (iv) future capital requirements. An estimate of the sensitivity to changes in assumptions resulting in future taxable income calculations is not practicable, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures.

We develop our estimate of demographic effects and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our U.S. pension plans and our other U.S. postretirement benefit plans due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary’s discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a recognized rating agency, callable bonds (with the exception of those meeting specific criteria including having more than 10 years remaining until maturity) and outlier bonds (bonds that have a yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is required to have at least $300 million par value outstanding. The constructed yield curve is based on those bonds representing the 50% highest yielding issuances within each defined maturity group.

We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, as well as tax disputes and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances outside legal counsel is utilized.

At December 31, 2022, our portfolio of current and long-term debt is comprised of floating rate debt and fixed-rate instruments. Our Term Loan Facility and Revolving Credit Facility are floating rate debt instruments, which exposes us to the risk of earnings or cash flow losses as the result of potential increases in market interest rates. At December 31, 2022, we had $2.0 billion in outstanding borrowings under floating rate debt instruments. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under these borrowings would have increased our interest expense by approximately $20 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

As described in Notes 1 and 10 to the consolidated financial statements, the Company’s consolidated property, plant and equipment, net balance was $17,377 million as of December 31, 2022, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2022, was $1,753 million. The Company follows the successful efforts method of accounting for its oil and gas producing activities. Under this method, capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. As disclosed by management, reserve estimates may change as additional information becomes available and as contractual, operational, economic and political conditions change. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity and future development costs, production history and continual reassessment of the viability of future production volumes under varying economic conditions. The estimates of oil and condensate, NGLs and natural gas reserves have been developed by specialists, specifically petroleum engineers and geoscientists.

As described in Note 4 to the consolidated financial statements, the Company completed the acquisition of assets and certain related liabilities from Ensign Natural Resources (“Ensign”) for cash consideration of $3.0 billion which resulted in the recording of $3.2 billion of property, plant, and equipment, of which proved and unproved oil and natural gas properties were a significant portion. Management accounted for the transaction under the acquisition method of accounting. Accordingly, the assets acquired and liabilities assumed were recognized at their fair values as of the closing date. Management prepared the estimates of fair values of proved and unproved oil and natural gas properties as of the acquisition date using discounted cash flows and engaged third party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, expected future production volumes, future realized commodity prices, future operating and development costs, and discount rate. The estimates of oil and condensate, NGLs and natural gas reserves have been developed by specialists, specifically petroleum engineers and geoscientists.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of proved and unproved oil and natural gas properties acquired. These procedures also included, among others (i) reading the purchase agreement, (ii) testing management’s process for developing the fair value estimate of proved and unproved oil and natural gas properties acquired, (iii) evaluating the appropriateness of the discounted cash flow models, (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow models, and (v) evaluating the reasonableness of significant assumptions used by management related to future production volumes, future realized commodity prices and the discount rate. Evaluating the reasonableness of management’s significant assumptions related to future realized commodity prices involved evaluating whether the significant assumptions used by management were reasonable considering external market and industry data and whether the assumptions were consistent with underlying contracts. The work of specialists was used in performing the procedures to evaluate the reasonableness of the future production volumes used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing of the completeness and accuracy of the data used by the specialists and evaluating the specialists’ findings. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the Company’s discounted cash flow models and the reasonableness of the discount rate significant assumption.


	Year Ended December 31,
(In millions, except per share data)	2022		2021		2020
Revenues and other income:
Revenues from contracts with customers	$	7,540	$	5,601	$	3,097
Net gain (loss) on commodity derivatives	(114)		(383)		116
Income (loss) from equity method investments	613		253		(161)
Net gain (loss) on disposal of assets	(38)		(19)		9
Other income	35		15		25
Total revenues and other income	8,036		5,467		3,086
Costs and expenses:
Production	690		534		555
Shipping, handling and other operating	733		727		596
Exploration	110		136		181
Depreciation, depletion and amortization	1,753		2,066		2,316
Impairments	7		60		144
Taxes other than income	484		345		200
General and administrative	308		291		274
Total costs and expenses	4,085		4,159		4,266
Income (loss) from operations	3,951		1,308		(1,180)
Net interest and other	(188)		(188)		(256)
Other net periodic benefit (costs) credits	16		5		(1)
Loss on early extinguishment of debt	—		(121)		(28)
Income (loss) before income taxes	3,779		1,004		(1,465)
Provision (benefit) for income taxes	167		58		(14)
Net income (loss)	$	3,612	$	946	$	(1,451)
Net income (loss) per share:
Basic	$	5.27	$	1.20	$	(1.83)
Diluted	$	5.26	$	1.20	$	(1.83)
Weighted average common shares outstanding:
Basic	685		787		792
Diluted	687		788		792


	December 31,
(In millions, except par values and share amounts)	2022		2021
Assets
Current assets:
Cash and cash equivalents	$	334	$	580
Receivables, net	1,146		1,142
Inventories	125		77
Other current assets	66		22

Total current assets	1,671		1,821
Equity method investments	577		450
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $23,876 and $22,412	17,377		14,499


Other noncurrent assets	315		224

Total assets	$	19,940	$	16,994
Liabilities
Current liabilities:
Accounts payable	$	1,279	$	1,110
Payroll and benefits payable	90		74
Accrued taxes	171		157
Other current liabilities	364		260
Long-term debt due within one year	402		36

Total current liabilities	2,306		1,637
Long-term debt	5,521		3,978
Deferred tax liabilities	167		136
Defined benefit postretirement plan obligations	100		137
Asset retirement obligations	295		288
Deferred credits and other liabilities	154		132

Total liabilities	8,543		6,308
Commitments and contingencies (Note 25)
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	—		—
Common stock:
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at December 31, 2022 and December 31, 2021)	937		937
Held in treasury, at cost – 304 million shares and 194 million shares	(7,512)		(4,825)
Additional paid-in capital	7,203		7,221
Retained earnings	10,663		7,271
Accumulated other comprehensive income	106		82
Total stockholders’ equity	11,397		10,686
Total liabilities and stockholders’ equity	$	19,940	$	16,994


	Year Ended December 31,
(In millions)	2022		2021		2020
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	3,612	$	946	$	(1,451)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,753		2,066		2,316
Impairments	7		60		144
Exploratory dry well costs and unproved property impairments	101		125		159
Net (gain) loss on disposal of assets	38		19		(9)
Loss on early extinguishment of debt	—		121		28
Deferred income taxes	(17)		(27)		(22)


Unrealized (gain) loss on derivative instruments, net	(18)		(16)		27
Pension and other post retirement benefits, net	(35)		(31)		(43)
Stock-based compensation	38		40		57
Equity method investments, net	(139)		(76)		210
Changes in:
Current receivables	9		(389)		367
Inventories	(45)		(1)		(4)
Current accounts payable and accrued liabilities	101		369		(381)
Other current assets and liabilities	(47)		46		75
All other operating, net	70		(13)		—
Net cash provided by operating activities	5,428		3,239		1,473
Investing activities:
Additions to property, plant and equipment	(1,450)		(1,046)		(1,343)
Additions to other assets	—		—		15
Acquisitions, net of cash acquired	(3,177)		(47)		(1)
Disposal of assets, net of cash transferred to the buyer	11		22		18
Equity method investments - return of capital	12		61		7
All other investing, net	(1)		—		1
Net cash used in investing activities	(4,605)		(1,010)		(1,303)
Financing activities:

Borrowings	1,500		—		400

Proceeds from revolving credit facility	450		—		—
Debt repayments	(35)		(1,400)		(500)

Debt extinguishment costs	—		(117)		(27)

Shares repurchased under buyback programs	(2,754)		(724)		(85)
Dividends paid	(220)		(141)		(64)
Purchases of shares for tax withholding obligations	(22)		(10)		(7)
All other financing, net	12		1		(3)
Net cash used in financing activities	(1,069)		(2,391)		(286)

Net increase (decrease) in cash and cash equivalents	(246)		(162)		(116)
Cash and cash equivalents at beginning of period	580		742		858

Cash and cash equivalents at end of period	$	334	$	580	$	742


	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Equity
December 31, 2019 Balance	$	—	$	937	$	(4,089)	$	7,207	$	7,993	$	105	$	12,153
Cumulative-effect adjustment	—		—		—		—		(12)		—		(12)
Shares repurchased under buyback programs	—		—		(85)		—		—		—		(85)
Stock-based compensation	—		—		85		(33)		—		—		52
Net loss	—		—		—		—		(1,451)		—		(1,451)
Other comprehensive loss	—		—		—		—		—		(32)		(32)
Dividends paid ($0.08 per share)	—		—		—		—		(64)		—		(64)

December 31, 2020 Balance	$	—	$	937	$	(4,089)	$	7,174	$	6,466	$	73	$	10,561
Shares repurchased under buyback programs	—		—		(724)		—		—		—		(724)
Stock-based compensation	—		—		(12)		47		—		—		35
Net income	—		—		—		—		946		—		946
Other comprehensive income	—		—		—		—		—		9		9
Dividends paid ($0.18 per share)	—		—		—		—		(141)		—		(141)

December 31, 2021 Balance	$	—	$	937	$	(4,825)	$	7,221	$	7,271	$	82	$	10,686
Shares repurchased under buyback programs	—		—		(2,754)		—		—		—		(2,754)
Stock-based compensation	—		—		67		(18)		—		—		49
Net income	—		—		—		—		3,612		—		3,612
Other comprehensive income	—		—		—		—		—		24		24
Dividends paid ($0.32 per share)	—		—		—		—		(220)		—		(220)


December 31, 2022 Balance	$	—	$	937	$	(7,512)	$	7,203	$	10,663	$	106	$	11,397

(Shares in millions)	Preferred Stock		Common Stock		Treasury Stock
December 31, 2019 Balance	—		937		141
Stock-based compensation	—		—		(2)
Shares repurchased under buyback programs	—		—		9
December 31, 2020 Balance	—		937		148
Stock-based compensation	—		—		—
Shares repurchased under buyback programs	—		—		46
December 31, 2021 Balance	—		937		194
Stock-based compensation	—		—		(3)
Shares repurchased under buyback programs	—		—		113
December 31, 2022 Balance	—		937		304

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options in all periods, provided the effect is not antidilutive. The per share calculations below exclude 2 million, 4 million and 7 million stock options for 2022, 2021 and 2020 that were antidilutive.


	Year Ended December 31,
(In millions, except per share data)	2022		2021		2020
Net income (loss)	$	3,612	$	946	$	(1,451)

Weighted average common shares outstanding	685		787		792
Effect of dilutive securities	2		1		—
Weighted average common shares, diluted	687		788		792
Net income (loss) per share:
Basic	$	5.27	$	1.20	$	(1.83)
Diluted	$	5.26	$	1.20	$	(1.83)
Dividends per share	$	0.32	$	0.18	$	0.08

All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGLs, and natural gas reserve estimates are reviewed and approved by asset leadership and our Corporate Reserves Group (“CRG”), which includes our Manager of Corporate Reserves and his staff. Crude oil and condensate, NGLs and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators (“QREs”). QREs are petro-technical professionals embedded within the asset teams who meet the qualifications we have established for employees engaged in estimating reserves. QREs have the education, experience and training necessary to estimate reserves in a manner consistent with all external reserve estimation regulations. QREs generally hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of five years of industry experience with at least three years in reserve estimation and have completed our QRE training course.

The estimation of net recoverable quantities of crude oil and condensate, NGLs and natural gas is a highly technical process which is based upon several underlying assumptions that are subject to change. Proved reserves are determined using “SEC Pricing”, calculated as an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month. As discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates, commodity prices are volatile which can have an impact on proved reserves. If commodity prices in the future average below prices used to determine proved reserves at December 31, 2022, it could have an adverse effect on our estimates of proved reserve volumes and the value of our business. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors.

Estimated Quantities of Proved Oil and Gas Reserves


(mmbbl)	U.S.	E.G.(a)	Total
Crude oil and condensate
Proved developed and undeveloped reserves:
Beginning of year - 2020	619	33	652
Revisions of previous estimates(b)	(120)	(2)	(122)

Extensions, discoveries and other additions(b)	50	—	50
Production	(65)	(5)	(70)
Sales of reserves in place	(1)	—	(1)
End of year - 2020	483	26	509
Revisions of previous estimates(b)	65	7	72
Purchases of reserves in place	3	—	3
Extensions, discoveries and other additions(b)	49	—	49
Production	(59)	(4)	(63)

End of year - 2021	541	29	570
Revisions of previous estimates	10	5	15
Purchases of reserves in place	62	—	62
Extensions, discoveries and other additions	60	—	60
Production	(58)	(4)	(62)

End of year - 2022	615	30	645
Proved developed reserves:
Beginning of year - 2020	304	30	334
End of year - 2020	301	23	324
End of year - 2021	332	26	358
End of year - 2022	354	30	384
Proved undeveloped reserves:
Beginning of year - 2020	315	3	318
End of year - 2020	182	3	185
End of year - 2021	209	3	212
End of year - 2022	261	—	261

Estimated Quantities of Proved Oil and Gas Reserves (continued)


(mmbbl)	U.S.	E.G.(a)	Total
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of year - 2020	204	21	225
Revisions of previous estimates(b)	(40)	(2)	(42)

Extensions, discoveries and other additions(b)	13	—	13
Production	(22)	(3)	(25)

End of year - 2020	155	16	171
Revisions of previous estimates(b)	43	4	47
Purchases of reserves in place	1	—	1
Extensions, discoveries and other additions(b)	24	—	24
Production	(23)	(2)	(25)

End of year - 2021	200	18	218
Revisions of previous estimates	35	2	37
Purchases of reserves in place	63	—	63
Extensions, discoveries and other additions	18	—	18
Production	(24)	(2)	(26)

End of year - 2022	292	18	310
Proved developed reserves:
Beginning of year - 2020	122	19	141
End of year - 2020	110	14	124
End of year - 2021	135	17	152
End of year - 2022	183	18	201
Proved undeveloped reserves:
Beginning of year - 2020	82	2	84
End of year - 2020	45	2	47
End of year - 2021	65	1	66
End of year - 2022	109	—	109

Estimated Quantities of Proved Oil and Gas Reserves (continued)


(bcf)	U.S.	E.G.(a)	Total
Natural gas
Proved developed and undeveloped reserves:
Beginning of year - 2020	1,278	690	1,968
Revisions of previous estimates(b)	(63)	5	(58)

Extensions, discoveries and other additions(b)	115	—	115
Production(c)	(155)	(121)	(276)
Sales of reserves in place	(1)	—	(1)
End of year - 2020	1,174	574	1,748
Revisions of previous estimates(b)	245	(13)	232

Purchases of reserves in place	3	—	3
Extensions, discoveries and other additions(b)	162	—	162
Production(c)	(138)	(95)	(233)

End of year - 2021	1,446	466	1,912
Revisions of previous estimates	44	62	106
Purchases of reserves in place	401	—	401
Extensions, discoveries and other additions	100	—	100
Production(c)	(132)	(92)	(224)

End of year - 2022	1,859	436	2,295
Proved developed reserves:
Beginning of year - 2020	825	649	1,474
End of year - 2020	827	526	1,353
End of year - 2021	998	439	1,437
End of year - 2022	1,223	436	1,659
Proved undeveloped reserves:
Beginning of year - 2020	453	41	494
End of year - 2020	347	48	395
End of year - 2021	448	27	475
End of year - 2022	636	—	636

Estimated Quantities of Proved Oil and Gas Reserves (continued)


(mmboe)	U.S.	E.G.(a)	Total
Total Proved Reserves
Proved developed and undeveloped reserves:
Beginning of year - 2020	1,036	169	1,205
Revisions of previous estimates(b)	(169)	(4)	(173)


Extensions, discoveries and other additions(b)	81	—	81
Production(c)	(112)	(28)	(140)
Sales of reserves in place	(1)	—	(1)
End of year - 2020	835	137	972
Revisions of previous estimates(b)	148	10	158

Purchases of reserves in place	4	—	4
Extensions, discoveries and other additions(b)	99	—	99
Production(c)	(104)	(23)	(127)

End of year - 2021	982	124	1,106
Revisions of previous estimates	53	18	71

Purchases of reserves in place	191	—	191
Extensions, discoveries and other additions	95	—	95
Production(c)	(104)	(21)	(125)

End of year - 2022	1,217	121	1,338
Proved developed reserves:
Beginning of year - 2020	563	158	721
End of year - 2020	549	125	674
End of year - 2021	634	115	749
End of year - 2022	741	121	862
Proved undeveloped reserves:
Beginning of year - 2020	473	11	484
End of year - 2020	286	12	298
End of year - 2021	348	9	357
End of year - 2022	476	—	476

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization


(In millions)	U.S.		E.G.		Total
Year Ended December 31, 2022
Capitalized Costs:
Proved properties	$	35,227	$	2,057	$	37,284
Unproved properties	3,177		—		3,177
Total	38,404		2,057		40,461
Accumulated depreciation, depletion and amortization:
Proved properties	21,118		1,776		22,894
Unproved properties	333		(7)		326
Total	21,451		1,769		23,220
Net capitalized costs	$	16,953	$	288	$	17,241
Year Ended December 31, 2021
Capitalized Costs:
Proved properties	$	31,626	$	2,056	$	33,682
Unproved properties	2,409		—		2,409
Total	34,035		2,056		36,091
Accumulated depreciation, depletion and amortization:
Proved properties	19,609		1,716		21,325
Unproved properties	413		(7)		406
Total	20,022		1,709		21,731
Net capitalized costs	$	14,013	$	347	$	14,360

Results of Operations for Oil and Gas Producing Activities


	U.S.		E.G.		Total
Year Ended December 31, 2022
Revenues and other loss
Sales	$	7,060	$	268	$	7,328
Other loss	(38)		—		(38)
Total revenues and other loss	7,022		268		7,290
Expenses:
Production costs(a)	(1,712)		(65)		(1,777)
Exploration expenses(b)	(110)		—		(110)
Depreciation, depletion and amortization(c)	(1,682)		(60)		(1,742)
Technical support and other	(53)		(3)		(56)
Total expenses	(3,557)		(128)		(3,685)
Results before income taxes	3,465		140		3,605
Income tax provision	(789)		(41)		(830)
Results of operations	$	2,676	$	99	$	2,775
Year Ended December 31, 2021
Revenues and other income:
Sales	$	4,828	$	265	$	5,093

Other income	9		—		9
Total revenues and other income	4,837		265		5,102
Expenses:
Production costs(a)	(1,388)		(56)		(1,444)
Exploration expenses(b)	(136)		—		(136)
Depreciation, depletion and amortization(c)	(2,032)		(68)		(2,100)
Technical support and other	(38)		(3)		(41)
Total expenses	(3,594)		(127)		(3,721)
Results before income taxes	1,243		138		1,381
Income tax provision	(7)		(37)		(44)
Results of operations	$	1,236	$	101	$	1,337
Year Ended December 31, 2020
Revenues and other income:
Sales	$	2,955	$	173	$	3,128

Other income	9		—		9
Total revenues and other income	2,964		173		3,137
Expenses:
Production costs(a)	(1,134)		(61)		(1,195)
Exploration expenses(b)	(175)		(6)		(181)
Depreciation, depletion and amortization(c)	(2,260)		(81)		(2,341)
Technical support and other	(48)		(3)		(51)
Total expenses	(3,617)		(151)		(3,768)
Results before income taxes	(653)		22		(631)
Income tax (provision) benefit	9		(5)		4
Results of operations	$	(644)	$	17	$	(627)

U.S. GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month as well as current costs applicable at the date of the estimate. These and other required assumptions have not always proved accurate in the past, and other valid assumptions would give rise to substantially different results. In addition, the 10% discount rate required to be used is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the oil and natural gas industry in general. This information is not the fair value, nor does it represent the expected present value of future cash flows of our crude oil and condensate, natural gas liquids and natural gas reserves.


(In millions)	U.S.		E.G.		Total
Year Ended December 31, 2022
Future cash inflows	$	80,247	$	2,278	$	82,525
Future production and support costs	(25,404)		(1,110)		(26,514)
Future development costs(a)	(6,848)		(54)		(6,902)
Future income tax expenses	(7,516)		(284)		(7,800)
Future net cash flows	$	40,479	$	830	$	41,309
10% annual discount for timing of cash flows	(18,807)		(279)		(19,086)
Standardized measure of discounted future net cash flows	$	21,672	$	551	$	22,223
Year Ended December 31, 2021
Future cash inflows	$	46,172	$	1,734	$	47,906
Future production and support costs	(17,212)		(880)		(18,092)
Future development costs(a)	(4,459)		(36)		(4,495)
Future income tax expenses	(2,526)		(209)		(2,735)
Future net cash flows	$	21,975	$	609	$	22,584
10% annual discount for timing of cash flows	(10,000)		(180)		(10,180)
Standardized measure of discounted future net cash flows	$	11,975	$	429	$	12,404
Year Ended December 31, 2020
Future cash inflows	$	21,847	$	941	$	22,788
Future production and support costs	(10,822)		(592)		(11,414)
Future development costs(a)	(3,977)		(19)		(3,996)
Future income tax expenses	(12)		(84)		(96)
Future net cash flows	$	7,036	$	246	$	7,282
10% annual discount for timing of cash flows	(3,207)		(56)		(3,263)
Standardized measure of discounted future net cash flows	$	3,829	$	190	$	4,019

Changes in the Standardized Measure of Discounted Future Net Cash Flows


	Year Ended December 31,
(In millions)	2022		2021(a)		2020(a)
Sales and transfers of oil and gas produced, net of production and support costs	$	(5,496)	$	(3,608)	$	(1,889)
Net changes in prices and production and support costs related to future production	8,643		8,013		(7,633)
Extensions, discoveries and improved recovery, less related costs	1,727		739		561
Development costs incurred during the period	1,232		795		801
Changes in estimated future development costs	(1,057)		20		2,970
Revisions of previous quantity estimates	1,379		2,460		(1,892)
Net changes in purchases and sales of minerals in place	4,090		(52)		(9)
Accretion of discount	1,335		374		1,031
Changes in timing and other	590		523		(1,116)
Net change in income taxes	(2,624)		(879)		440
Net change for the year	9,819		8,385		(6,736)
Beginning of the year	12,404		4,019		10,755
End of the year	$	22,223	$	12,404	$	4,019

Our code of ethics for Senior Financial Officers, which applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, is contained in our Code of Business Conduct, which is available on our website at www.marathonoil.com under Investors—Corporate Governance. You may request a printed copy free of charge by sending a request to the Corporate Secretary. We intend to disclose any amendments and any waivers to our Code of Business Conduct that apply to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions and relate to any element of the Code of Business Conduct enumerated in Item 406(b) of Regulation S-K on our website at www.marathonoil.com under Investors —Corporate Governance within four business days. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

Exhibit Number

Incorporated by Reference (File No. 001-05153, unless otherwise indicated)

Exhibit Description

Form

Exhibit

Filing Date

99.2*

Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2022

99.3*

Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2022

99.4*

Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2022

101.INS*

XBRL Instance Document - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH*

XBRL Taxonomy Extension Schema

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase

101.DEF*

XBRL Taxonomy Extension Definition Linkbase

101.LAB*

XBRL Taxonomy Extension Label Linkbase

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase

104*

Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101

Filed herewith.

†

Management contract or compensatory plan or arrangement.

Each person whose signature appears below appoints Lee M. Tillman, Dane E. Whitehead, and Rob L. White, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, with full power and authority to each of said attorneys-in-fact and agents to do and perform each and every act whatsoever that is necessary, appropriate or advisable in connection with any or all of the above-described matters and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their substitutes, may lawfully do or cause to be done by virtue hereof.


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended	December 31, 2022
☐	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	1-1513


Delaware						25-0996816
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


Table of Contents
			Page
PART I
	Items 1. and 2.	Business and Properties	6
	Item 1A.	Risk Factors	21
	Item 1B.	Unresolved Staff Comments	33
	Item 3.	Legal Proceedings	33
	Item 4.	Mine Safety Disclosures	34
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
	Item 6.	[Reserved]	34
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	52
	Item 8.	Financial Statements and Supplementary Data	53
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	113
	Item 9A.	Controls and Procedures	113
	Item 9B.	Other Information	113
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	113
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	114
	Item 11.	Executive Compensation	114
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	114
	Item 14.	Principal Accountant Fees and Services	115
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	115
	Item 16.	Form 10-K Summary	120
		SIGNATURES	121


	December 31,
(Dollars per unit)	2022		2021		2020
Average Sales Price per Unit (a)
Crude oil and condensate (bbl)
United States	$	95.58	$	66.88	$	35.93

E.G.	68.67		57.46		28.36




Total	$	94.03	$	66.25	$	35.39

Natural gas liquids (bbl)
United States	$	34.55	$	28.89	$	11.28

E.G. (b)	1.00		1.00		1.00




Total	$	31.34	$	26.19	$	9.97

Natural gas (mcf)
United States	$	6.11	$	4.57	$	1.77

E.G. (b)	0.24		0.24		0.24




Total	$	3.70	$	2.81	$	1.10



Average Production Costs per Unit (c)
United States	$	11.94	$	9.99	$	8.40

E.G.	3.04		2.48		2.16




Total	$	10.42	$	8.66	$	7.15


Sales Mix - U.S. Resource Plays - 2022	Eagle Ford	Bakken	Oklahoma	Permian	Total
Crude oil and condensate	66%	64%	23%	55%	56%
Natural gas liquids	17%	23%	32%	22%	23%
Natural gas	17%	13%	45%	23%	21%


	Crude Oil and Condensate (mmbbl)		Natural Gas Liquids (mmbbl)		Natural Gas (bcf)		Total (mmboe)		Total (%)
Proved Developed Reserves
U.S.	354		183		1,223		741		55	%
E.G.	30		18		436		121		9	%

Total proved developed reserves (mmboe)	384		201		1,659		862		64	%
Proved Undeveloped Reserves
U.S.	261		109		636		476		36	%
E.G.	—		—		—		—		—	%

Total proved undeveloped reserves (mmboe)	261		109		636		476		36	%
Total Proved Reserves
U.S.	615		292		1,859		1,217		91	%
E.G.	30		18		436		121		9	%

Total proved reserves (mmboe)	645		310		2,295		1,338		100	%
Total proved reserves (%)	48	%	23	%	29	%	100	%


	Productive Wells
	Oil		Natural Gas		Service Wells		Drilling Wells
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2022
U.S.	5,774	2,644	2,179	1,255	150	16	8	7
E.G.	—	—	17	11	—	—	—	—

Total	5,774	2,644	2,196	1,266	150	16	8	7
2021
U.S.	5,375	2,452	1,554	633	147	16
E.G.	—	—	19	12	—	—
Total	5,375	2,452	1,573	645	147	16
2020
U.S.	5,225	2,302	1,592	648	198	21
E.G.	—	—	19	12	—	—

Total	5,225	2,302	1,611	660	198	21


	Developed		Undeveloped		Developed and Undeveloped
(In thousands)	Gross	Net	Gross	Net	Gross	Net
U.S.	1,624	1,005	110	104	1,734	1,109
E.G.	82	67	—	—	82	67

Total	1,706	1,072	110	104	1,816	1,176


	Net Undeveloped Acres Expiring
	Year Ended December 31,
(In thousands)	2023	2024	2025
U.S.	79	12	4
E.G.	—	—	—
Total	79	12	4


Net Sales Volumes	2022	Increase (Decrease)		2021	Increase (Decrease)		2020
United States (mboed)	284	(1)	%	286	(7)	%	306
International (mboed)	59	(3)	%	61	(21)	%	77
Total (mboed)	343	(1)	%	347	(9)	%	383


Drilling Activity - U.S. Resource Plays	2022	2021	2020
Gross Operated
Eagle Ford:
Wells drilled to total depth	105	91	88
Wells brought to sales	111	117	87
Bakken:
Wells drilled to total depth	50	72	63
Wells brought to sales	53	71	64
Oklahoma:
Wells drilled to total depth	18	—	9
Wells brought to sales	33	8	13
Permian:
Wells drilled to total depth	21	—	15
Wells brought to sales	19	7	19


			Increase (Decrease) Related to
(In millions)	Year Ended December 31, 2021		Price Realizations		Net Sales Volumes		Year Ended December 31, 2022
United States Price/Volume Analysis
Crude oil and condensate	$	3,925	$	1,667	$	(40)	$	5,552
Natural gas liquids	653		133		28		814
Natural gas	632		204		(27)		809
Other sales	124						93
Total	$	5,334					$	7,268
International Price/Volume Analysis
Crude oil and condensate	$	240	$	40	$	(36)	$	244
Natural gas liquids	2		—		—		2
Natural gas	23		—		(1)		22
Other sales	2						4
Total	$	267					$	272


(In millions; rate in $ per boe)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Production Expense and Rate	Expense						Rate
United States	$	625	$	480	30	%	$	6.03	$	4.60	31	%
International	$	65	$	54	20	%	$	3.04	$	2.45	24	%


	Impact of a 10% Increase in Proved Reserves				Impact of a 10% Decrease in Proved Reserves
(In millions, except per boe)	DD&A per boe		Pretax Income		DD&A per boe		Pretax Income
United States	$	(1.47)	$	152	$	1.80	$	(186)
International	$	(0.26)	$	5	$	0.31	$	(7)


(In millions)	Fair Value at December 31, 2022		Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%

Derivative asset – Natural Gas	$	10	$	8	$	14


	December 31,
	2022		2021		2020
Percentage of Total Commodity Sales
Marathon Petroleum Corporation	22	%	17	%	13	%
Valero Marketing and Supply	12	%	10	%	N/A
Trafigura Groupe Pte. Ltd.	10	%	N/A		N/A
Koch Resources LLC	N/A		N/A		12	%


Risks Associated with Our Industry


Regulatory Compliance and International Operations Risks


General Risks


(In millions)	Fair Value at December 31, 2022		Hypothetical Interest Rate Increase of 10%		Hypothetical Interest Rate Decrease of 10%
Interest rate asset (liability) – designated as cash flow hedges	$	24	$	28	$	20


			Page
Management’s Responsibilities for Financial Statements			54
Management’s Report on Internal Control over Financial Reporting			54
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 238)			55
Audited Consolidated Financial Statements
Consolidated Statements of Income			58
Consolidated Statements of Comprehensive Income			59
Consolidated Balance Sheets			60
Consolidated Statements of Cash Flows			61
Consolidated Statements of Stockholders’ Equity			62
Notes to Consolidated Financial Statements

1. Summary of Principal Accounting Policies			63
2. New Accounting Standards			67
3. Income (loss) and Dividends per Common Share			67
4. Acquisitions			67
5. Revenues			68
6. Segment Information			71
7. Income Taxes			73
8. Credit Losses			76
9. Inventories			77
10. Property, Plant and Equipment			77
11. Impairments			78
12. Asset Retirement Obligations			79
13. Leases			79
14. Goodwill			82
15. Derivatives			82
16. Fair Value Measurements			86
17. Debt			88
18. Incentive Based Compensation			89
19. Defined Benefit Postretirement Plans and Defined Contribution Plan			92
20. Reclassifications out of AOCI			95
21. Supplemental Cash Flow Information			96
22. Other Items			96
23. Equity Method Investments			96
24. Stockholders' Equity			97
25. Commitments and Contingencies			98
Supplementary Information on Oil and Gas Producing Activities (Unaudited)			100


/s/ Lee M. Tillman						/s/ Dane E. Whitehead
Chairman, President and Chief Executive Officer						Executive Vice President and Chief Financial Officer


		December 31,
Type of Asset	Range of Useful Lives	2022		2021
		(In millions)
Office furniture, equipment and computer hardware	4 to 15 years	$	36	$	41
Pipelines	5 to 40 years	$	13	$	10
Plants, facilities and infrastructure	3 to 40 years	$	1,510	$	1,496


(In millions)	December 27, 2022
Assets:

Inventories	$	4

Total current assets acquired	4
Property, plant and equipment	3,159

Total assets acquired	$	3,163
Liabilities:

Other current liabilities	$	36
Total current liabilities assumed	36
Asset retirement obligations	41
Other noncurrent liabilities	58
Total liabilities assumed	135
Net assets acquired	$	3,028


(In millions)	Operating Lease Obligations		Finance Lease Obligations		Total Lease Obligations
2023	$	101	$	7	$	108
2024	20		7		27
2025	6		6		12
2026	2		5		7
2027	—		—		—
Thereafter	—		—		—
Total undiscounted lease payments	$	129	$	25	$	154
Less: amount representing interest	3		1		4
Total lease liabilities	$	126	$	24	$	150
Less: current portion of lease liability as of December 31, 2022	94		6		100
Long-term lease liability as of December 31, 2022	$	32	$	18	$	50


(In millions)	Operating Lease Future Cash Receipts
2023	$	6
2024	6
2025	6
2026	6
2027	6
Thereafter	42
Total undiscounted cash flows	$	72


	December 31, 2022
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	10	$	—	$	10	Other current assets



Total Not Designated as Hedges	$	10	$	—	$	10
Cash Flow Hedges
Interest Rate	$	9	$	—	$	9	Other current assets
Interest Rate	15		—		15		Other noncurrent assets
Total Designated Hedges	$	24	$	—	$	24
Total	$	34	$	—	$	34


	December 31, 2021
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	1	$	8	$	(7)	Other current liabilities

Interest Rate	27		—		27		Other noncurrent assets
Total Not Designated as Hedges	$	28	$	8	$	20
Cash Flow Hedges
Interest Rate	$	—	$	3	$	(3)	Other current liabilities
Interest Rate	—		2		(2)		Deferred credits and other liabilities
Total Designated Hedges	$	—	$	5	$	(5)
Total	$	28	$	13	$	15


	2023
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
























Natural Gas





Henry Hub Two-Way Collars
Volume (MMBtu/day)	50,000		—		—		—
Weighted average price per MMBtu:
Ceiling	$	19.28	$	—	$	—	$	—
Floor	$	5.00	$	—	$	—	$	—
Henry Hub Three-Way Collars
Volume (MMBtu/day)	50,000		50,000		50,000		50,000
Weighted average price per MMBtu:
Ceiling	$	11.14	$	11.14	$	11.14	$	11.14
Floor	$	4.00	$	4.00	$	4.00	$	4.00
Sold Put	$	2.50	$	2.50	$	2.50	$	2.50


	December 31, 2022				December 31, 2021
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR

June 1, 2025	$	—	—	%	$	350	0.95	%
September 9, 2026	$	—	—	%	$	25	1.45	%


	December 31, 2022
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	—	$	10	$	—	$	10

Interest rate - designated as cash flow hedges	—		24		—		24
Derivative instruments, assets	$	—	$	34	$	—	$	34







	December 31, 2021
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate - not designated as cash flow hedges	$	—	$	27	$	—	$	27

Derivative instruments, assets	$	—	$	27	$	—	$	27
Derivative instruments, liabilities
Commodity(a)	$	(2)	$	(5)	$	—	$	(7)
Interest rate - designated as cash flow hedges	—		(5)		—		(5)
Derivative instruments, liabilities	$	(2)	$	(10)	$	—	$	(12)
Total	$	(2)	$	17	$	—	$	15


	2020
Exercise price per share	$	10.47
Expected annual dividend yield	1.9		%
Expected life in years	6.14
Expected volatility	44		%
Risk-free interest rate	1.5		%
Weighted average grant date fair value of stock option awards granted	$	3.82


	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value (in millions)
Outstanding at beginning of year	4,274,304	$	22.13
Granted	—	$	—
Exercised/Vested	(2,176,680)	$	14.73
Canceled	(419,100)	$	33.56
Outstanding at end of year	1,678,524	$	28.86	2 years	$	5
Exercisable at end of year	1,389,461	$	32.69	1 year	$	—
Expected to vest	289,063	$	10.47	7 years	$	5


	Awards	Weighted Average Grant Date Fair Value
Unvested at beginning of year	5,888,242	$	10.98
Granted	1,848,387	$	22.81
Vested	(2,863,779)	$	11.99
Canceled	(221,654)	$	14.61
Unvested at end of year	4,651,196	$	14.89


	Pension Benefits			Other Benefits
	2022		2021			2022	2021
(In millions)	U.S.			U.S.				U.S.		U.S.
Accumulated benefit obligation	$	214		$	260			$	53	$	73

Change in pension benefit obligations:
Beginning balance	$	269		$	308			$	73	$	80
Service cost	14			16				—		—
Interest cost	7			7				2		2


Actuarial (gain) loss	(46)			(15)				(11)		1




Settlements paid	(21)			(43)				—		—
Benefits paid	(5)			(4)				(11)		(10)
Ending balance	$	218		$	269			$	53	$	73
Change in fair value of plan assets:
Beginning balance	$	192		$	194			$	—	$	—
Actual return on plan assets	(27)			13				—		—
Employer contributions	22			32				11		10



Settlements paid	(21)			(43)				—		—
Benefits paid	(5)			(4)				(11)		(10)
Ending balance	$	161		$	192			$	—	$	—
Funded status of plans at December 31	$	(57)		$	(77)			$	(53)	$	(73)
Amounts recognized in the consolidated balance sheets:

Current liabilities	$	(3)		$	(3)			$	(8)	$	(10)
Noncurrent liabilities	(54)			(74)				(45)		(63)
Accrued benefit cost	$	(57)		$	(77)			$	(53)	$	(73)
Pretax amounts in accumulated other comprehensive loss:
Net loss	$	24		$	37			$	11	$	23
Prior service credit	(8)			(13)				(65)		(81)


	Ownership as of	December 31,
(In millions)	December 31, 2022	2022		2021
EGHoldings (a)	56%	$	287	$	148
Alba Plant LLC (b)	52%	155		154
AMPCO (c)	45%	135		148
Total		$	577	$	450


(mmboe)
Beginning of year			357
Revisions of previous estimates			40
Purchases of reserves in place			86
Extensions, discoveries and other additions			86

Transfers to proved developed			(93)
End of year			476


February 16, 2023						MARATHON OIL CORPORATION

						By: /s/ ROB L. WHITE
						Rob L. White
						Vice President, Controller and Chief Accounting Officer


Signature						Title

/s/ LEE M. TILLMAN						Chairman, President and Chief Executive Officer
Lee M. Tillman

/s/ DANE E. WHITEHEAD						Executive Vice President and Chief Financial Officer
Dane E. Whitehead

/s/ ROB L. WHITE						Vice President, Controller and Chief Accounting Officer
Rob L. White

/s/ CHADWICK C. DEATON						Director
Chadwick C. Deaton

/s/ MARCELA E. DONADIO						Director
Marcela E. Donadio

/s/ M. ELISE HYLAND						Director
M. Elise Hyland

/s/ HOLLI C. LADHANI						Director
Holli C. Ladhani

/s/ MARK A. MCCOLLUM						Director
Mark A. McCollum

/s/ BRENT J. SMOLIK						Director
Brent J. Smolik

/s/ J. KENT WELLS						Director
J. Kent Wells

/s/ SHAWN D. WILLIAMS						Director
Shawn D. Williams