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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
  For the Fiscal Year Ended December 31, 2020
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
MRO-20201231_G1.JPG
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware   25-0996816
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, Texas 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol   Name of each exchange on which registered
Common Stock, par value $1.00 MRO   New York Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  o No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer
o  
Non-accelerated filer
o   
Smaller reporting company Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o    
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  No   þ
The aggregate market value of Common Stock held by non-affiliates as of June 30, 2020: $4,814 million. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.
There were 789,075,988 shares of Marathon Oil Corporation Common Stock outstanding as of February 12, 2021.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2021 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this report.



MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our” or “us” in this Annual Report on Form 10-K are references to Marathon Oil Corporation, including its wholly owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
Table of Contents
Page

5



Definitions
Throughout this report, the following company or industry specific terms and abbreviations are used.
AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea in which we own a 45% equity interest.
AMT – Alternative minimum tax.
bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
boe – Barrels of oil equivalent.
btu – British thermal unit, an energy equivalence measure.
BLM – Bureau of Land Management.
Capital Budget – Includes capital expenditures, cash investments in equity method investees and other investments, exploration costs that are expensed as incurred rather than capitalized, such as geological and geophysical costs and certain staff costs, and other miscellaneous investment expenditures.
CWA – Clean Water Act.
DD&A – Depreciation, depletion and amortization.
Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry well – A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.
E.G. – Equatorial Guinea.
EGHoldings – Equatorial Guinea LNG Holdings Limited, a liquefied natural gas production company located in E.G. in which we own a 60% equity interest.
ESG – Environmental, safety and governance.
EPA – United States Environmental Protection Agency.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.
FASB – Financial Accounting Standards Board.
Henry Hub – a natural gas benchmark price quoted at settlement date average.
IRS – United States Internal Revenue Service.
Kurdistan – Kurdistan Region of Iraq.
LIBOR – London Interbank Offered Rate.
LNG – Liquefied natural gas.
LPG – Liquefied petroleum gas.
Liquid hydrocarbons or liquids – Collectively, crude oil, condensate and natural gas liquids.
LLS – Louisiana Light Sweet crude oil, an oil index benchmark price as per Bloomberg Finance LLP: LLS St. James.
MEH – Magellan East Houston, an oil index benchmark price of WTI at Magellan East Houston.
Marathon Oil – Marathon Oil Corporation, including wholly owned and majority-owned subsidiaries, and ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest). The company as it exists following the June 30, 2011 spin-off of the refining, marketing and transportation operations.
mbbld – Thousand barrels per day.
mboed – Thousand barrels of oil equivalent per day.
mcf – Thousand cubic feet.
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mmbbl – Million barrels.
mmboe – Million barrels of oil equivalent. Natural gas is converted on the basis of six mcf of gas per one barrel of crude oil equivalent.
mmbtu – Million British thermal units.
mmcfd – Million stabilized cubic feet per day.
mmta – Million metric tonnes per annum.
mt – Metric tonnes.
mtd – Metric tonnes per day.
NAAQS – National Ambient Air Quality Standard.
Net acres or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.
NGL or NGLs – Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, which can be collectively removed from produced natural gas, separated into these substances and sold.
NYMEX – New York Mercantile Exchange.
OPEC – Organization of Petroleum Exporting Countries.
Operational availability A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time, after consideration of planned maintenance.
Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.
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.
Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic viability at greater distances.
Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of liquid hydrocarbons and natural gas produced.
REx – Resource play exploration.
Royalty interest – An interest in an oil or natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
SAR or SARs – Stock appreciation right or stock appreciation rights.
SCOOP – South Central Oklahoma Oil Province.
SEC – United States Securities and Exchange Commission.
Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures and 4-D factors in changes that occurred over time).
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STACK – Sooner Trend (oil field), Anadarko (basin), Canadian (and) Kingfisher (counties) in Oklahoma.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
Turnaround – A planned major maintenance program the costs for which are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.
U.K. – United Kingdom.
U.S. – United States of America.
U.S. resource plays – Consists of our unconventional properties in the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico.
U.S. GAAP – U.S. Generally Accepted Accounting Principles.
Working interest – The interest in a mineral property, which gives the owner that share of production from the property. A working interest owner bears that share of the costs of exploration, development and production in return for a share of production. Working interests are sometimes burdened by overriding royalty interests or other interests.
WOTUS – Waters of the United States.
WTI – West Texas Intermediate crude oil, an oil index benchmark price as quoted by NYMEX.

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Disclosures Regarding Forward-Looking Statements
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 2021 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; growth expectations; 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,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “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:
conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;
changes in expected reserve or production levels;
changes in political or economic conditions in the U.S. and E.G., including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
actions taken by the members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia affecting the production and pricing of crude oil and other global and domestic political, economic or diplomatic developments;
capital available for exploration and development;
risks related to our hedging activities;
voluntary or involuntary curtailments, delays or cancellations of certain drilling activities;
well production timing;
liability resulting from litigation;
drilling and operating risks;
lack of, or disruption in, access to storage capacity, pipelines or other transportation methods;
availability of drilling rigs, materials and labor, including the costs associated therewith;
difficulty in obtaining necessary approvals and permits;
non-performance by third parties of their contractual obligations;
unforeseen hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks;
changes in safety, health, environmental, tax and other regulations, or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;
other geological, operating and economic considerations; and
other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.



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PART I
Items 1. and 2. Business and Properties
General and Business Strategy
General
Marathon Oil Corporation (NYSE: MRO) is an independent exploration and production company incorporated in 2001, focused on U.S. resource plays: the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico. Our U.S. assets are complimented by our international operations in E.G. Our corporate headquarters is located at 5555 San Felipe Street, Houston, Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our two reportable operating segments are organized by geographic location and managed according to the nature of the products and services offered. The two segments are:
United States – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States;
International – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
Business Strategy
Our overall business strategy is to deliver competitive and improving corporate level returns and sustainable free cash flow through a disciplined reinvestment rate capital allocation framework. Our framework prioritizes free cash flow generation across a broad range of commodity prices by limiting our capital expenditures relative to our expected cash flow from operations. Our strategy includes making a significant portion of our cash flow from operations available for investor-friendly purposes, prioritizing return of capital to shareholders and balance sheet enhancement. We are committed to creating long-term value for shareholders. Protecting our balance sheet, keeping our workforce safe, minimizing our environmental impact, and strong corporate governance are foundational to the execution of our strategy.
MRO-20201231_G2.JPG
In February 2021, we announced a 2021 Capital Budget of $1.0 billion, which is effectively a maintenance Capital Budget. We expect this maintenance-level Capital Budget will allow us to keep total company oil production in 2021 consistent with our fourth quarter 2020 exit rate. Our 2021 Capital Budget is consistent with our capital allocation framework that prioritizes corporate returns and free cash flow generation over production growth.
The risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely for at least a portion of the time. We have begun a process for a phased return of employees to the office. Working remotely has not significantly impacted our
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ability to maintain operations, has allowed our field offices to operate without any disruption, and has not caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures.
We have taken action in response to the macro challenges and the uncertainty associated with the timeline for recovery. Our response has included reducing our 2020 and 2021 capital expenditure programs, lowering our cost structure and protecting our balance sheet, liquidity and cash generation. We believe our financial strength, quality portfolio and ongoing focus on reducing our cost structure better position us to navigate a variety of commodity price environments. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, for a more detailed discussion of our operating results, cash flows and liquidity.
Our portfolio is concentrated in our core operations in the U.S. resource plays and E.G. The map below shows the locations of our U.S. operations:
MRO-20201231_G3.JPG
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Segment Information
In the following discussion regarding our United States and International segments, references to net wells, acres, sales or investment indicate our ownership interest or share, as the context requires.
United States Segment
We are engaged in oil and gas exploration, development and production activities in the U.S. Our primary focus in the United States segment is concentrated within our four high-quality resource plays. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for further detail on current year results.
United States – U.S. Resource Plays
Eagle Ford – We have been operating in the South Texas Eagle Ford play since 2011, where our acreage is located in the high-return Karnes, Atascosa, Gonzales and Lavaca Counties. Our focus is capital efficient development with a goal of maximizing returns and free cash flow generation. We operate 32 central gathering and treating facilities across the play that support more than 1,600 producing wells. We also own and operate the Sugarloaf gathering system, a 42-mile natural gas pipeline through the heart of our acreage in Karnes and Atascosa Counties.
Bakken – We have been operating in the Williston Basin since 2006. The majority of our core acreage is within McKenzie, Mountrail and Dunn Counties in North Dakota targeting the Middle Bakken and Three Forks reservoirs. We continue focusing our investment in our high-return Myrmidon and Hector areas, while also delineating and extending our core acreage across the rest of our position.
Oklahoma – With a history in Oklahoma that dates back more than 100 years, our primary focus has been development in the STACK Meramec and SCOOP Woodford, while progressing delineation of other plays across our footprint. We primarily hold net acreage with rights to the Woodford, Springer, Meramec, Osage and other prospect intervals, with a majority of this in the SCOOP and STACK.
Northern Delaware – We have been operating in the Northern Delaware basin, which is located within the greater Permian area, since closing on two major acquisitions in 2017. Our focus has been to strategically advance our position, progress early delineation and development of our acreage, improve our cost structure and secure midstream solutions. We have the majority of our acreage in Eddy and Lea counties primarily in the Wolfcamp and Bone Spring New Mexico plays.
United States – Resource Exploration
In the second quarter of 2020, Marathon Oil completed its 2020 REx drilling program. We continued delineation of our contiguous 58,000 net acreage position in the Texas Delaware Oil Play and successfully brought online four Woodford wells and two Meramec wells since entering the play. These wells demonstrated strong productivity, low decline and low water/oil ratios relative to the industry Delaware Basin Wolfcamp and Bone Spring wells and advanced our geologic understanding of the play.
We evaluated the geologic potential of our 186,000 net acre position in the Louisiana Austin Chalk and determined that approximately 78,000 acres remain in the prospective core of the formation. We will continue our assessment of the prospective acreage. We also recognized an impairment of an abandoned well and the unproved acreage that we determined was non-core. See Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements for further detail about the impairments.
International Segment
We are engaged in oil and gas development and production activities in E.G. We include the results of our investments in the LPG processing plant, gas liquefaction operations and methanol production operations in E.G. in our International segment.
International
Equatorial Guinea – We own a 63% operated working interest under a production sharing contract in the Alba field and an 80% operated working interest in Block D, both of which are offshore E.G. Operational availability from our company-operated facilities averaged approximately 99% in 2020.
Equatorial Guinea – Gas Processing – We own a 52% interest in Alba Plant LLC, accounted for as an equity method investment, which operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas is processed by the LPG plant under a fixed-price long-term contract. The LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations.
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We also own 60% of EGHoldings and 45% of AMPCO, both accounted for as equity method investments. EGHoldings operates a 3.7 mmta LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to further monetize natural gas production from the Alba field. The LNG production facility sells LNG under a 3.4 mmta sales and purchase agreement. Under the current agreement, which runs through 2023, the purchaser takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index. Gross sales of LNG from this production facility totaled approximately 3 mmta in 2020. AMPCO had gross sales totaling approximately 827 mt in 2020. Methanol production is sold to customers in Europe and the U.S.
During 2019, we executed agreements for third-party gas through existing E.G. infrastructure, the initial step in creating an E.G. gas hub. Natural gas from the Alen field will be processed through the existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production facility. Alen’s first gas production was achieved in February 2021. Our equity method investees will process the Alen gas under a combination of a tolling and profit-sharing arrangement, the benefits of which will be included in our respective share of income from equity method investees.
Reserves
Proved reserves are required to be disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15% or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. For additional detail on reserves, see Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities.
The following tables set forth estimated quantities of our total proved crude oil and condensate, NGLs and natural gas reserves based upon SEC pricing for period ended December 31, 2020.
Crude Oil and Condensate
(mmbbl)
Natural Gas Liquids
(mmbbl)
Natural Gas
(bcf)
Total
(mmboe)
Total (%)
Proved Developed Reserves
U.S. 301  110  827  549  56  %
E.G. 23  14  526  125  13  %
Total proved developed reserves (mmboe)
324  124  1,353  674  69  %
Proved Undeveloped Reserves
U.S. 182  45  347  286  30  %
E.G. 48  12  %
Total proved undeveloped reserves (mmboe)
185  47  395  298  31  %
Total Proved Reserves
U.S. 483  155  1,174  835  86  %
E.G. 26  16  574  137  14  %
Total proved reserves (mmboe)
509  171  1,748  972  100  %
Total proved reserves (%) 52  % 18  % 30  % 100  %








8


Productive and Drilling Wells
For our United States and International segments, the following table sets forth gross and net productive wells, service wells and drilling wells as of December 31 for the years presented.
  Productive Wells        
  Oil Natural Gas Service Wells Drilling Wells
  
Gross Net Gross Net Gross Net Gross Net
2020
U.S. 5,225  2,302  1,592  648  198  21  16 
E.G. —  —  19  12  —  —  —  — 
Total 5,225  2,302  1,611  660  198  21  16 
2019
U.S. 4,984  2,195  1,550  615  204  20 
E.G. —  —  19  12  —  — 
Total (a)
4,984  2,195  1,569  627  204  20 
2018
U.S. 4,630  2,056  1,703  655  209  21 
E.G. —  —  19  12  —  — 
Other International 62  22  11  24 
Total 4,692  2,078  1,733  671  233  29 
(a)Other International was removed from 2019 due to the sale of our U.K. business and our 15% non-operated interest in the Atrush block in Kurdistan. See Item 8. Financial Statements and Supplementary Data Note 5 to the consolidated financial statements for further information.

Drilling Activity
Our drilling activity was lower during the year ended December 31, 2020 as compared to 2019 and 2018 driven by the macro environment and the reduction in our Capital Budget. The table below sets forth the number of net productive and dry development and exploratory wells completed as of December 31 for the years represented, all of which reside in our United States segment, unless noted in the table below.
December 31,
2020 2019 2018
Development
Oil 103 197 171
Natural Gas 15 28 25
Dry
Total Development 118 225 196
Exploratory
Oil 30 57 66
Natural Gas 14 26 36
Dry(a)
2 3
Total Exploratory 44 85 105
Total 162 310 301
(a)2018 includes one dry well in our E.G. segment associated with the Rodo well in Alba Block Sub Area B, offshore E.G.





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Acreage
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.
The following table sets forth, by geographic area, the gross and net developed and undeveloped acreage held as of December 31, 2020.
  Developed Undeveloped Developed and
Undeveloped
(In thousands) Gross Net Gross Net Gross Net
U.S. 1,380  993  306  247  1,686  1,240 
E.G. 82  67  —  —  82  67 
Total 1,462  1,060  306  247  1,768  1,307 
In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. If production is not established or we take no other action to extend the terms of the leases, undeveloped acreage listed in the table below could expire over the next three years. We plan to continue the terms of certain of these leases through operational or administrative actions. There are no material quantities of net proved undeveloped reserves assigned to expiring undeveloped acreage in the next three years.
Net Undeveloped Acres Expiring
Year Ended December 31,
(In thousands) 2021 2022 2023
U.S. 94  48  94 
E.G. —  —  — 
Total 94  48  94 
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Net Sales Volumes
At December 31, 2020, 2019 and 2018, the Eagle Ford, Bakken and Oklahoma fields 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,
2020 2019 2018
Net Sales Volumes
Crude oil and condensate (mbbld) (a)
United States
Eagle Ford 61  63  63 
Bakken 79  86  71 
Oklahoma 17  21  18 
Northern Delaware 15  16  12 
 Other U.S.
Africa
E.G. 13  15  17 
Libya —  — 
Other International (b)
—  15 
Total 190  210  210 
Natural gas liquids (mbbld)
United States
Eagle Ford 18  22  23 
Bakken 14 
Oklahoma 20  22  20 
Northern Delaware
 Other U.S.
Africa
E.G. 11 
Total 68  69  66 
Natural gas (mmcfd) (c)
United States
Eagle Ford 121  130  129 
Bakken 70  46  35 
Oklahoma 177  210  213 
Northern Delaware 41  36  26 
 Other U.S. 14  16  26 
Africa
E.G. 330  365  416 
Libya —  — 
Other International (b)
—  14 
Total 753  809  864 
Total sales volumes (mboed)
United States
Eagle Ford 99  106  108 
Bakken 105  103  84 
Oklahoma 66  78  74 
Northern Delaware 27  28  20 
 Other U.S. 12 
Africa
E.G. 77  85  97 
Libya —  — 
Other International (b)
—  17 
Total 383  414  420 
(a)The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b)Other International sales include sales volumes for the U.K. and the Atrush block in Kurdistan, which were both sold in 2019 and sales volumes for the non-operated Sarsang block in Kurdistan which was sold in 2018. See Item 8. Financial Statements and Supplementary Data Note 5 to the consolidated financial statements for further information.
(c)Includes natural gas acquired for injection and subsequent resale.
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Average Sales Price and Production Costs per Unit are presented by geographic area.
  December 31,
(Dollars per unit) 2020 2019 2018
Average Sales Price per Unit (a)
Crude oil and condensate (bbl)
United States $ 35.93  $ 55.80  $ 63.11 
Africa
E.G. 28.36  48.99  55.28 
Libya —  —  73.75 
Total Africa 28.36  48.99  60.65 
Other International (b)
—  64.71  70.39 
Total $ 35.39  $ 55.54  $ 63.32 
Natural gas liquids (bbl)
United States $ 11.28  $ 14.22  $ 24.54 
Africa
E.G. (c)
1.00  1.00  1.00 
Total Africa 1.00  1.00  1.00 
Other International (b)
—  37.88  41.66 
Total $ 9.97  $ 12.46  $ 20.85 
Natural gas (mcf)
United States $ 1.77  $ 2.18  $ 2.65 
Africa
E.G. (c)
0.24  0.24  0.24 
Libya —  —  4.57 
Total Africa 0.24  0.24  0.30 
Other International (b)
—  5.67  8.03 
Total $ 1.10  $ 1.33  $ 1.58 
Average Production Costs per Unit (d)
U.S. $ 8.40  $ 9.08  $ 9.83 
E.G. 2.16  2.34  1.91 
Libya —  —  4.35 
Other International (b)
—  30.42  30.02 
Total $ 7.15  $ 8.03  $ 8.68 
(a)Excludes gains or losses on commodity derivative instruments.
(b)Other International sales include sales volumes for the U.K. and the Atrush block in Kurdistan, which were both sold in 2019 and sales volumes for the non-operated Sarsang block in Kurdistan which was sold in 2018. See Item 8. Financial Statements and Supplementary Data Note 5 to the consolidated financial statements for further information.
(c)Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and/or EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International segment.
(d)Taxes other than income (such as production, severance and property taxes) are excluded; however, shipping and handling as well as other operating expenses are included in the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities Results of Operations for Oil and Gas Production Activities for more information regarding production costs.




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Marketing
Our reportable operating segments include activities related to the marketing and transportation of substantially all of our crude oil and condensate, NGLs and natural gas. These activities include the transportation of production to market centers, the sale of commodities to third parties and the storage of production. We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the purchase of commodities from third parties for resale.
Major Customers
We are exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. In 2020, sales to Marathon Petroleum Corporation and Koch Resources LLC and each of their respective affiliates, accounted for approximately 13% and 12% of our total revenues. In 2019, sales to Marathon Petroleum Corporation, Koch Resources LLC, Valero Marketing and Supply and Shell Trading and each of their respective affiliates, accounted for approximately 13%, 13%, 11% and 10% of our total revenues. In 2018, sales to Valero Marketing and Supply and Koch Resources LLC and their respective affiliates, each accounted for approximately 11% of our total revenues.
Gross Delivery Commitments
We have committed to deliver gross quantities of crude oil and condensate, NGLs and natural gas to customers under a variety of contracts. As of December 31, 2020, the contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to the following commitments:
2021 2022 2023 Thereafter Commitment Period Through
Eagle Ford
Crude and condensate (mbbld)
33 2021
Natural gas (mmcfd)
148 128 92 12 2025
Bakken
Crude and condensate (mbbld)
21 12 10 5 - 10 2027
Natural gas (mmcfd)
14 2021
Other United States
Natural gas (mmcfd)
4 1 2022
All of these contracts provide the option of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate to satisfy our commitment. In addition to the contracts discussed above, we have entered into numerous agreements for transportation and processing of our equity production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms.
Competition
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, in the exploration for and development of new reserves, acquisition of oil and natural gas leases and other properties, 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.
Government Regulations
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 and the costs of compliance with these new laws and regulations can only be broadly appraised until their implementation becomes more defined. However, the new federal administration has indicated its intent to increase regulatory oversight of oil and gas activity specifically, and to
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put climate change at the forefront of its policy initiatives. We expect these policies to be wide-ranging and include executive branch action to address climate change and accelerate development of renewable resources.
The new administration has already issued a number of executive and temporary orders that address broad ranging issues including climate change, oil and gas activities on federal lands, infrastructure, and environmental justice. At this time, applicability of the actions taken by the new administration appear to largely exclude tribal lands and we do not believe that the new executive and temporary orders currently in effect will have a material adverse impact on our business. Amendments or extensions along with implementation of the announced policy positions and initiatives that flow from these orders may have a material adverse impact on our business.
We also expect continued introduction of legislation on issues that may impact our business including climate change, COVID-19 relief, tax matters and access to capital.
While there are not currently regulations proposed or pending that we believe will result in material capital, operating, tax or other costs to the business at this time, such regulations could be proposed and/or passed into law in 2021 or beyond. Other regulations currently in place could be withdrawn and replaced with more stringent requirements in 2021 or beyond.
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 has the responsibility to ensure 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 which oversees our response to any major environmental or other emergency incident involving us or any of our properties.
Environmental Remediation and Waste Management
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 controls for minimization of pollution or recordkeeping, monitoring and reporting requirements or other operational or siting constraints on our business, result in costs to remediate releases of regulated substances, including crude oil and produced water, into the environment, or require costs to remediate 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.
Waste regulations include those for management, storage, transportation and disposal. Additional or expanded regulations relating to oilfield waste may be adopted that potentially impact the costs of compliance, handling, management and availability of disposal options.
Air and Climate Change
Concerns about emissions of carbon dioxide, methane, and other greenhouse gases and their role in climate change may affect us and other similarly situated companies operating in the oil and gas industry. Further, recent actions by the federal government have signaled an intent to take significant action to address climate change. In addition, legislative proposals to address some of these issues have already begun and we expect additional proposals under the current federal administration that may become law. Until such proposals or actions are in final form, we cannot fully evaluate potential impacts, but as part of our commitment to environmental stewardship and as required by law, we estimate and publicly report greenhouse gas emissions from our operations. We are also working to continuously improve the accuracy and completeness of these estimates. Moreover, we are making a concentrated effort to improve operational and energy efficiencies through resource and energy conservation. Finally, we have also undertaken initiatives to reduce our flaring and GHG emissions intensity and 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 global warming 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.
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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 choose to do so, will be required to complete development of implementation plans in the 2021-2022 time frame. The EPA may in the future designate additional areas as non-attainment, including areas in which we operate. In August 2020, EPA completed its review of the ozone NAAQS and proposed to retain the 2015 standard without revision. The final rule has not yet been published. The implementation of the 2015 standard, or the promulgation of a future more stringent standard, 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, 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.
Hydraulic Fracturing
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 operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements.
The new federal administration has included as part of its platform actions that could amount to a de facto ban on hydraulic fracturing on federal lands (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.
Water
In 2014, the EPA and the U.S. Army Corps of Engineers published proposed regulations which expand the surface waters that are regulated under the federal CWA and its various programs. While these regulations were finalized largely as proposed in 2015, the rule was stayed by the courts pending a substantive decision on the merits. In October 2019, EPA and the Army Corps of Engineers issued a final rule that repealed the 2015 regulations and reinstated the agencies’ narrower pre-2015 scope of federal CWA jurisdiction. In January 2020, EPA and the Army Corps of Engineers promulgated a new WOTUS definition that continues to provide a narrower scope of federal CWA jurisdiction than contemplated under the 2015 WOTUS definition, while also providing for greater predictability and consistency of federal CWA jurisdiction. That rule was published in April 2020 and became effective in June 2020 except for in the state of Colorado, where the rule is stayed pending a challenge by the State of Colorado. Judicial challenges to EPA’s 2019 and 2020 rules are currently before multiple federal district courts. If the October 2019 final rule is vacated and the 2015 rule is ultimately implemented, or if the current administration promulgates a new rule similar in scope to the 2015 rule, the expansion of CWA jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.
Other Oil and Gas Regulations
In November 2016, the BLM issued a final rule to further restrict venting and/or flaring of gas from facilities subject to BLM jurisdiction, and to modify certain royalty requirements. Following judicial challenge, the court invalidated the rule. If this ruling is overturned on appeal, or the new administration re-issues a similar or more stringent rule, the requirements could result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.
For additional information, see Item 1A. Risk Factors.
Trademarks, Patents and Licenses
We currently hold U.S. and foreign patents. Although in the aggregate our trademarks and patents are important to us, we do not regard any single trademark, patent, or group of related trademarks or patents as critical or essential to our business as a whole.


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Human Capital Management
Oversight and Management
We believe talent is one of the critical capabilities foundational to delivering on our corporate strategy. Intentional human capital management strategies enable us to attract, develop, retain and reward our dedicated employees. Marathon believes in creating a safe, clean and ethical environment where employees feel empowered to make a difference to achieve 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. 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 on a regular cadence, including the review of compensation, benefits, succession, HES and corporate social responsibility. Please visit marathonoil.com/sustainability for information on all dimensions of our corporate social responsibility.
Our People
We believe in promoting an inclusive corporate culture to ensure the strength and resilience of our business. Respectful relationships are core to our culture. Our Code of Business Conduct, which applies to our directors, officers and employees, prohibits workplace harassment, violence and discrimination against anyone based on race, age, national origin, sexual orientation, gender identity and other factors. This code applies to all aspects of employment at Marathon Oil – recruitment, training, development, compensation, performance management and benefits. We select, develop and promote employees based on the individual’s ability and job performance.
Our Talent Landscape
As of December 31, 2020, we had 1,672 active, full-time employees worldwide. Approximately 73% of our full-time workforce was based in the United States with 27% in Equatorial Guinea. Through recruiting, training, workforce integration, education and vocational programs, we strive to have a workforce reflective of the areas in which we operate. In 2020 and as a result of prioritized nationalization efforts, 90% of our Marathon EG Production Limited (MEGPL), workforce was Equatoguinean. For information on our Executive Officers, see Information About Our Executive Officers

For the U.S. workforce, our average tenure for full-time employees was 8 years, with 28% of our full-time population having 10 or more years of experience. As of December 31, 2020, women and minorities accounted for 34% and 30% of our U.S. full-time workforce, respectively. We encourage diversity and inclusion 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. In 2020, we launched an additional ERG to continue our efforts towards promoting a diverse and inclusive culture. Additionally, we are implementing a new workforce flexibility program in 2021 to capitalize on our learnings working from home in 2020 while preserving our collaborative and One Team culture. The new flexibility program will provide broader options for our employees to better manage their career, work-life balance and overall well-being.

Recognizing the cyclical nature of our business and the dynamic talent demands, we conduct a proactive risk analysis as part of our Enterprise Risk Management process, including a multi-year view of any potential talent risks to ensure we are prepared to respond to the macro- environment while setting ourselves up for long-term success. We fully leverage our common asset team organizational structure to drive knowledge sharing, collaboration and talent deployment across these teams resulting in efficiency gains and enhanced execution. Our partners and contractors are an essential element to our business and we follow a well-defined, rigorous evaluation process to ensure the partners we select uphold our expectations and core values. We utilize a managed service provider to oversee efficient administration, equitable treatment and compliance auditing of our contingent labor workforce.
Health, Environment and Safety
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 Health, Environment and Safety (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 full-time contractors as part of our Responsible Operations Management Systems or 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.

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We leverage our collective talent and seek diverse employee perspectives to address complex issues and events through the use of multi-functional teams and committees such as our internal Centralized Emergency Response Team (CERT) and Emissions Management Committee (EMC). Specifically, our comprehensive response to COVID-19 leaned heavily on our CERT team and our business continuity plans to protect both our workforce and sustain the essential services that our company provides. The EMC prioritizes GHG and methane emissions reduction opportunities across our enterprise and ensures appropriate funding is in place as part of our overall capital allocation process. Our commitment to addressing the dual challenge of meeting the world’s growing energy demands while also taking action on climate change is evidenced by GHG intensity featuring prominently as a metric linked directly to compensation outcomes.

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 ensure a safe, healthy and secure workplace where all those involved can work free of injury and illness. Our Total Recordable Injury Rate (TRIR) is 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.
Benefits
We attract and retain talent by offering benefit programs that are competitive and comprehensive. These programs create flexibility that allows employees to receive the benefits that we believe allow employees to develop a career and overall well-being for themselves and their families. In 2021, we increased our family leave to create additional optionality for a greater portion of our employees to better manage their career and overall well-being. 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 oil and gas industry. We believe effective communication around our benefit programs helps ensure we understand employees' perceptions and values around our benefits and to confirm our employees understand the breadth and value of the benefits provided.
Compensation
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. 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. To pay competitively, 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.
Talent Development
We take a multi-pronged approach to organizational learning which is driven through our centralized on-demand development hub and informed by our enterprise-wide talent assessment process. Our organizational learning approach blends online, on-the-job and classroom training with 360 assessments and leadership coaching to ensure all employees receive the feedback, tools and time they need to reach their fullest potential. Continuous leadership development is offered to all leaders throughout the year and content is intentionally focused on learning objectives.

We review talent across the enterprise, measuring both technical and leadership capabilities. 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 set employees up for success in future senior leadership roles.
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Information About our Executive Officers
The executive officers of Marathon Oil and their ages as of February 1, 2021, are as follows:
Lee M. Tillman 59 Chairman, President and Chief Executive Officer
Dane E. Whitehead 59 Executive Vice President—Chief Financial Officer
Patrick J. Wagner 56 Executive Vice President—Corporate Development and Strategy
Mike Henderson 51 Senior Vice President—Operations
Kimberly O. Warnica 47 Senior Vice President—General Counsel
Gary E. Wilson 59 Vice President, Controller and Chief Accounting Officer
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 senior vice president, operations in May 2020, after having served 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 senior vice president, general counsel in January 2021. Prior to joining Marathon Oil she was executive vice president, general counsel, chief compliance officer and corporate 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.
Mr. Wilson was appointed vice president, controller and chief accounting officer in October 2014. Prior to joining Marathon Oil, he served in various finance and accounting positions of increasing responsibility at Noble Energy, Inc. (a global exploration and production company) since 2001, including as director of corporate accounting from February 2014 through September 2014, director of global operations services finance from October 2012 through February 2014, director of controls and reporting from April 2011 through September 2012, and international finance manager from September 2009 through March 2011.
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Available Information
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 5555 San Felipe Street, Houston, Texas, 77056-2723, 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.
Additionally, we make available free of charge on our website:
our Code of Business Conduct and Code of Ethics for Senior Financial Officers;
our Corporate Governance Principles; and
the charters of our Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee.
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Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under “Disclosures Regarding Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report on Form 10-K.
Risks Associated with our Industry
A substantial decline in crude oil and condensate, NGLs and natural gas prices would reduce our operating results and cash flows and could adversely impact our future rate of growth and the carrying value of our assets.
The markets for crude oil and condensate, NGLs and natural gas have been volatile and are likely to continue to be volatile in the future, causing prices to fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil and condensate, NGLs and natural gas. Many of the factors influencing prices of crude oil and condensate, NGLs and natural gas are beyond our control. These factors include:
worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas;
the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas;
the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls and agreed cuts;
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
political instability or armed conflict in oil and natural gas producing regions;
changes in weather patterns and climate;
natural disasters such as hurricanes and tornadoes;
the price and availability of alternative and competing forms of energy, such as nuclear, hydroelectric, wind or solar;
the effect of conservation efforts;
epidemics or pandemics, including the recent novel coronavirus global pandemic, known as COVID-19;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxes, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels; and
general economic conditions worldwide.
The long-term effects of these and other factors on the prices of crude oil and condensate, NGLs and natural gas are uncertain. Historical declines in commodity prices have adversely affected our business by:
reducing the amount of crude oil and condensate, NGLs and natural gas that we can produce economically;
reducing our revenues, operating income and cash flows;
causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
requiring us to impair the carrying value of our assets;
reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and natural gas; and
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
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Estimates of crude oil and condensate, NGLs and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our reserves.
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 our in-house 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, 2020, 2019 and 2018, as well as other conditions in existence at those dates. The table below provides the 2020 SEC pricing for certain benchmark prices:
2020 SEC Pricing
WTI crude oil (per bbl)
$ 39.57 
Henry Hub natural gas (per mmbtu)
$ 1.99 
Brent crude oil (per bbl)
$ 41.77 
Mont Belvieu NGLs (per bbl)
$ 14.41 
If crude oil prices in the future average below prices used to determine proved reserves at December 31, 2020, 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.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be directly measured. Estimates of economically producible reserves and of future net cash flows depend on a number of variable factors and assumptions, including:
location, size and shape of the accumulation, as well as fluid, rock and producing characteristics of the accumulation;
historical production from the area, compared with production from other analogous producing areas;
the assumed impacts of regulation by governmental agencies;
assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
industry economic conditions, levels of cash flows from operations and other operating considerations.
As a result, different petroleum engineers and geoscientists, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ materially from the estimated amounts:
the amount and timing of production;
the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.
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. 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. For example, in early July, a U.S. district court ordered the Dakota Access Pipeline to halt oil flow and empty the pipeline within 30 days because the United States Army Corps of Engineers did not conduct a full Environmental Impact Statement. Though a federal appellate court has administratively stayed the shutdown, if a shutdown occurs, we will need to use alternative means to transport approximately 10,000 bpd (on a net basis) of our Bakken oil. A shutdown could also have an impact on safety (because it would require the use of additional trucks, rail cars and personnel) and could negatively impact our Bakken price differentials, all of which could adversely affect the results of our operations. In addition, both the cost and availability of pipelines, rail cars, trucks, or vessels to transport our production could be adversely impacted by new and expected state or federal regulations relating to transportation of crude oil.
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If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
We typically seek the acquisition of crude oil and natural gas properties and leases. 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, nor may they permit us to become sufficiently familiar with the properties in order to fully assess possible deficiencies and potential problems. 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 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.
Future exploration and drilling results are uncertain and involve substantial costs.
Drilling for crude oil and condensate, NGLs and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
inflation in exploration and drilling costs;
fires, explosions, blowouts or surface cratering;
lack of, or disruption in, access to pipelines or other transportation methods; and
shortages or delays in the availability of services or delivery of equipment.
We operate in a highly competitive industry, and many of our competitors are larger and have available resources in excess of our own.
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.
Our offshore operations involve special risks that could negatively impact us.
Offshore operations present technological challenges and operating risks because of the marine environment. Activities in offshore operations may pose risks because of the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities.

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Risks Related to Our Business Model and Capital Structure
If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and condensate, NGLs and natural gas production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.
The rate of production from crude oil and condensate, NGLs and natural gas properties generally declines 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:
obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas in promising areas;
drilling success;
the ability to complete projects timely and cost effectively;
the ability to find or acquire additional proved reserves at acceptable costs; and
the ability to fund such activity.
If crude oil and condensate, NGLs and natural gas prices decrease, it could adversely affect the abilities of our counterparties to perform their obligations to us which could negatively impact our financial results.
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.
If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Delays or cost increases related to capital spending programs involving drilling and completion activities, engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
increased costs or operational delays resulting from shortages of water;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
Any one or more of these factors could have a significant impact on our capital projects.
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Our level of indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2020, our total debt was $5.4 billion, and our next debt maturity is our $0.5 billion 2.8% senior unsecured notes due in 2022. Our indebtedness could have important consequences to our business, including, but not limited to, the following:
we may be more vulnerable to general adverse economic and industry conditions;
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
our flexibility in planning for, or reacting to, changes in our industry may be limited;
a financial covenant in our unsecured revolving credit facility (the “Credit Facility”) stipulates that our total debt to total capitalization ratio will not exceed 65% as of the last day of any fiscal quarter, and if exceeded, may make additional borrowings more expensive and affect our ability to plan for and react to changes in the economy and our industry;
we may be at a competitive disadvantage as compared to similar companies that have less debt; and
additional financing in the future for working capital, capital expenditures, acquisitions or development activities, general corporate or other purposes may have higher costs and more restrictive covenants.
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 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 18 to the consolidated financial statements for a discussion of debt obligations.
Difficulty in accessing capital or a significant increase in our costs of accessing capital could adversely affect our business.
We receive credit ratings on our debt obligations from the major credit rating agencies in the United States. Due to the volatility in crude oil and U.S. natural gas prices in recent years, credit rating agencies review companies in the energy industry periodically, including us. At December 31, 2020, our corporate credit ratings were: Standard & Poor’s Global Ratings Services BBB- (stable); Fitch Ratings BBB- (stable); and Moody’s Investor Services, Inc. Baa3 (negative). The credit rating process is contingent upon a number of factors, many of which are beyond our control. 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 may limit or reduce credit lines with our bank counterparties. 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.
Our commodity price risk management activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.
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.
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Many of our major projects and operations are conducted jointly with other parties, which may decrease our ability to manage risk.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production with other parties in order to share risks associated with those operations. However, these arrangements also may decrease our ability to manage risks and costs, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. In addition, misconduct, fraud, bankruptcy, noncompliance with applicable laws and regulations or improper activities by or on behalf of one or more of our partners or co-working interest owners, or entities we have entered into arrangements with could have a significant negative impact on our business and reputation.
Regulatory Compliance and International Operations Risks
We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in law, regulations or requirements or initiatives, including those addressing environmental, health, safety or security or the impact of global climate change, air emissions or water management, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Our businesses are currently subject to numerous laws, regulations, executive orders and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions, including carbon dioxide and methane, and the protection of endangered species as well as laws, regulations and other requirements relating to public and employee safety and health and to facility security.
The new administration has already issued a number of executive and temporary orders that address broad ranging issues including climate change, oil and gas activities on federal lands, infrastructure, and environmental justice. At this time, applicability of the actions taken by the new administration appear to largely exclude tribal lands and we do not believe that the new executive and temporary orders currently in effect will have a material adverse impact on our business. Amendments or extensions along with implementation of the announced policy positions and initiatives that flow from these orders may have a material adverse impact on our business.
Additionally, states in which we operate may: impose additional regulations legislation, or requirements, such as the proposed methane emission rules in New Mexico; begin initiatives addressing the impact of global climate change, air emissions or water management; or we may become subject to 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.
The new 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 agreement includes provisions that every country take some action to lower emissions. In November 2019, the U.S. served notice on the United Nations that it would withdraw from the Paris Agreement in 2020. In January 2021, President Biden rejoined the Paris Agreement on behalf of the U.S. which will require signatory countries to set voluntary targets to reduce domestic emissions and create stricter goals, which may ultimately result in additional laws or regulations restricting our emissions of GHGs. Moreover, some states and local governments may choose to re-implement the terms of the agreement in whole or in part. 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
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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.
The potential adoption of federal, state and local legislative and regulatory initiatives related to hydraulic fracturing could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells. 
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. In 2015 the BLM issued a rule governing certain hydraulic fracturing practices on lands within their jurisdiction; however, this rule was rescinded in December 2017. In March 2020, the U.S. District Court for the Northern District of California upheld the rescission.
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 potential adoption of federal, state and local legislative and regulatory initiatives intended to address potential induced seismic activity in the areas in which we operate could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells. 
    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. When caused by human activity, such events are called induced seismicity. 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. Marathon uses hydraulic fracturing techniques throughout its U.S. operations.
While the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, Oklahoma has taken numerous regulatory actions in response to concerns related to the operation of produced water disposal wells and induced seismicity, and has issued guidelines to operators in certain areas of the State curtailing injection of produced water due to seismic concerns. Marathon does not currently own or operate injection wells or contract for such services in these areas. Further, Oklahoma issued guidelines to operators for management of anomalous seismicity that may be related to hydraulic fracturing activities in the SCOOP/STACK area. In addition, a number of lawsuits have been filed in Oklahoma alleging damage from seismicity relating to disposal well operations. Marathon has not been named in any of those lawsuits.
    Increased seismicity in Oklahoma or other areas could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and gas activities.
Political and economic developments, possible terrorist activities and changes in law or policy in the U.S. or global markets could adversely affect our operations and materially reduce our profitability and cash flows.
Local political and economic factors in U.S. and global markets could have a material adverse effect on us. We are subject to the political, geographic and economic risks and possible terrorist or piracy activities or other armed conflict attendant to doing business within or outside of the U.S. There are also many risks associated with operations in E.G. including the possibility that the government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens.
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
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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.
General Risks
Our business, financial conditions and results of operations have been adversely affected and may continue to be adversely affected by the recent COVID-19 global pandemic.
Any widespread outbreaks of contagious diseases have the potential to impact our business and operations. The recent novel coronavirus global pandemic, known as COVID-19, has had a material adverse impact on our business, financial condition and results of operations and the continued impact of COVID-19 could be material. The current effects of COVID-19 include a substantial decline in demand for crude oil, condensate, NGLs, natural gas and other petroleum hydrocarbons, along with a corresponding deterioration in prices. In addition, COVID-19, combined with the resulting economic downturn 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 restraints; 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 our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely as we plan a process to phase employees to return to the office. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures. The extent to which COVID-19 will impact our business and our financial results will depend on future developments, which are highly uncertain and cannot be predicted.
As a result, at the time of this filing, it is not possible to predict the overall impact of COVID-19 on our business, liquidity, capital resources and financial results.
Our business could be negatively impacted by cyberattacks targeting our computer and telecommunications systems and infrastructure, or targeting those of our third-party service providers.
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 on whom we 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. Use of the internet and other public networks for communications, services and storage, including “cloud” computing, exposes all users (including our business) to cybersecurity risks.
While we and our third-party service providers commit resources to the design, implementation and monitoring of our information systems, there is no guarantee that our security measures will provide absolute security. Despite these security measures, 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 information security breaches and significant disruption to our business. Our information systems and related infrastructure have experienced attempted and actual minor breaches of our cybersecurity 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. 
As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to investigate and remediate any information
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systems and related infrastructure security vulnerabilities. We may also be subject to regulatory investigations or litigation relating from cybersecurity issues.
Our business may be materially adversely affected by negative publicity.
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, could lead to adverse press coverage and other adverse public statements affecting the Company. 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 subject to business interruptions and casualty losses. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities and increased costs.
Our United States and International operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, tornadoes, hurricanes and other adverse weather, tsunamis, earthquakes, volcanic eruptions or nuclear or other disasters, labor disputes and accidents. These same risks can be applied to the third-parties which transport our products from our facilities. A prolonged disruption in the ability of any pipelines, rail cars, trucks, or vessels to transport our production could contribute to a business interruption or increase costs.
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.
Litigation by private plaintiffs or government officials or entities could adversely affect our performance.
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, 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. 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.
Item 1B. Unresolved Staff Comments
None.
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Item 3. Legal Proceedings
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
See Item 8. Financial Statements and Supplementary Data – Note 26 to the consolidated financial statements for a description of such legal and administrative proceedings.
Environmental Proceedings
The following is a summary of certain proceedings involving us that were pending or contemplated as of December 31, 2020, under federal and state environmental laws.
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 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. 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.
As of December 31, 2020, we have sites across the country where remediation is being sought under environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation.  Based on currently available information the accrued amount to address the clean-up and remediation costs connected with these sites is not material. In December 2019, we received a Notice of Violation from the North Dakota Department of Environmental Quality related to a release of produced water in North Dakota and a verbal notice of enforcement in January 2020 from the North Dakota Industrial Commission, related to a release of produced water in North Dakota. In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. The enforcement actions will likely result in monetary sanctions and corrective actions yet-to-be specified; however, we do not believe these enforcement actions would have a material adverse effect on our consolidated financial position, results of operations or cash flow.
    If our assumptions relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts. 
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange (“NYSE”), and is traded under the trading symbol ‘MRO’. As of January 31, 2021, there were 27,680 registered holders of Marathon Oil common stock.
Dividends – Our Board of Directors intends to declare and pay dividends on Marathon Oil common stock based on our financial condition and results of operations, although it has no obligation under Delaware law or the restated certificate of incorporation to do so. In determining our dividend policy, the Board of Directors will rely on our consolidated financial statements. Dividends on Marathon Oil common stock are limited to our legally available funds.
The following table provides information about purchases by Marathon Oil and its affiliated purchaser, during the quarter ended December 31, 2020, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
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)
10/01/2020 - 10/31/2020 22,423  $ 3.95  —  $ 1,320,335,751 
11/01/2020 - 11/30/2020 —  $ —  —  $ 1,320,335,751 
12/01/2020 - 12/31/2020 1,162  $ 5.86  —  $ 1,320,335,751 
Total 23,585  $ 4.05  — 
(a)23,585 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b)In January 2006, we announced a $2 billion share repurchase program. Our Board of Directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2 billion in July 2007, by $1.2 billion in December 2013 and by $950 million in July 2019 for a total authorized amount of $7.2 billion.
As of December 31, 2020, we have repurchased 191 million common shares at a cost of approximately $5.9 billion, excluding transaction fees and commissions. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination by the Board of Directors prior to completion. In connection with the economic downturn, during the second quarter of 2020, the Company temporarily suspended the share repurchase program. Shares repurchased as of December 31, 2020 were held as treasury stock.

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Item 6.   Selected Financial Data
Year Ended December 31,
(In millions, except per share data) 2020 2019 2018 2017 2016
Statement of Income Data(a)
Total revenues and other income $ 3,086  $ 5,190  $ 6,582  $ 4,765  $ 3,787 
Income (loss) from continuing operations $ (1,451) $ 480  $ 1,096  $ (830) $ (2,087)
Discontinued operations(b)
$ —  $ —  $ —  $ (4,893) $ (53)
Net income (loss) $ (1,451) $ 480  $ 1,096  $ (5,723) $ (2,140)
Per Share Data(a)
Basic:
Income (loss) from continuing operations $ (1.83) $ 0.59  $ 1.30  $ (0.97) $ (2.55)
Discontinued operations(b)
$ —  $ —  $ —  $ (5.76) $ (0.06)
Net income (loss) $ (1.83) $ 0.59  $ 1.30  $ (6.73) $ (2.61)
Diluted:
Income (loss) from continuing operations $ (1.83) $ 0.59  $ 1.29  $ (0.97) $ (2.55)
Discontinued operations(b)
$ —  $ —  $ —  $ (5.76) $ (0.06)
Net income (loss) $ (1.83) $ 0.59  $ 1.29  $ (6.73) $ (2.61)
Statement of Cash Flows Data
Additions to property, plant and equipment related to continuing operations
$ (1,343) $ (2,550) $ (2,753) $ (1,974) $ (1,204)
Dividends paid
$ (64) $ (162) $ (169) $ (170) $ (162)
Dividends per share
$ 0.08  $ 0.20  $ 0.20  $ 0.20  $ 0.20 
Balance Sheet Data at December 31
Total assets $ 17,956  $ 20,245  $ 21,321  $ 22,012  $ 31,094 
Total long-term debt, including capitalized leases $ 5,404  $ 5,501  $ 5,499  $ 5,494  $ 6,581 
Leases:(c)
Right-of-use asset $ 133  $ 199  $ —  $ —  $ — 
Current portion of long-term lease liability $ 70  $ 101  $ 62  $ 29  $ 30 
Long-term lease liability $ 67  $ 107  $ 155  $ 90  $ 146 
(a)December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million.
(b)We closed on the sale of our Canada business in 2017 and have reflected this business as Discontinued Operations in the periods presented.
(c)Note the prospective adoption of the lease accounting standard on January 1, 2019. Therefore, current and long-term portions for leases in years 2016 through 2018 do not reflect adoption of the new lease accounting standard. See Item 8. Financial Statements and Supplementary Data Note 2 and Note 14 to the consolidated financial statements for further information.

    Supplemental information affecting comparability of selected financial data is shown below.
Year Ended December 31,
(In millions) 2020 2019 2018 2017 2016
Proved property impairment $ 49  $ 24  $ 75  $ 229  $ 67 
Unproved property impairment $ 157  $ 98  $ 208  $ 246  $ 195 
Goodwill impairment $ 95  $ —  $ —  $ —  $ — 
Equity method investment impairment $ 171  $ —  $ —  $ —  $ — 
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and the other financial information found elsewhere in this Form 10-K. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See “Disclosures Regarding Forward-Looking Statements” (immediately prior to Part I) and Item 1A. Risk Factors.
Each of our two reportable operating segments are organized by geographic location and managed according to the nature of the products and services offered.
United States – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States;
International – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
Executive Overview
We are an independent exploration and production company based in Houston, Texas. Our strategy is to deliver competitive and improving corporate level returns and sustainable free cash flow through disciplined investment across our U.S. resource plays (the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico). Our reinvestment rate capital allocation framework prioritizes free cash flow generation across a wide range of commodity prices to make available significant cash flow for investor-friendly purposes, including return of capital to shareholders and balance sheet enhancement. Protecting our balance sheet, keeping our workforce safe, minimizing our environmental impact and strong corporate governance are foundational to the execution of our strategy.
The risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely for at least a portion of the time. We have begun a process for a phased return of employees to the office. Working remotely has not significantly impacted our ability to maintain operations, has allowed our field offices to operate without any disruption, and has not caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures.
Key 2020 highlights include:
Reducing and optimizing our Capital Budget
In February 2020, we announced an approved 2020 Capital Budget of $2.4 billion, including $200 million to fund REx. Given the substantial decline in commodity prices and oversupply in the market, our Board of Directors approved two separate reductions, culminating in a revised Capital Budget of $1.2 billion. The revised budget contemplated a full suspension of our Oklahoma activity in 2020, a decrease in Northern Delaware and REx drilling programs, and optimization of our development plans in the Bakken and Eagle Ford.
Maintained focus on balance sheet and liquidity
At the end of the fourth quarter 2020, we had approximately $3.7 billion of liquidity, comprised of an undrawn $3.0 billion Credit Facility and $0.7 billion in cash. We remain investment grade at all three primary rating agencies.
In 2020, we generated $1.5 billion of cash provided by operating activities despite the lower commodity price realizations and decreased production volumes. This was sufficient to fund our capital expenditures, share repurchases and dividends.
In early July 2020, collected an $89 million cash refund related to alternative minimum tax credits and associated interest. This was an accelerated refund due to the passage of the Coronavirus Aid, Relief, and Economic Security Act.
In the fourth quarter of 2020, we realized over $400 million of cash from operations. Our U.S. segment average realized prices for crude and NGLs for the quarter were $39.71 and $16.30, respectively.
We reduced our gross debt by $100 million and reduced our next significant debt maturity.
We remarketed $400 million sub-series B (tax-exempt) bonds in August at a weighted average interest rate of 2.25%.
In October, we completed a cash tender for $500 million of our then-outstanding $1 billion 2.8% 2022 Notes, funded by cash on hand.
The next significant debt maturity is the remaining $500 million 2.8% Senior Notes due in November 2022.
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During the second quarter 2020, we temporarily suspended the quarterly dividend and share repurchases to maximize liquidity. On October 1, the Board of Directors approved and declared the reinstatement of the base quarterly dividend of $0.03 per share, effective in the fourth quarter of 2020. While our share repurchase program remains approved with $1.3 billion of repurchase authorization remaining at year-end, we decided to maintain the suspension as we continue to maximize liquidity.
Managed our cost structure
Achieved lower production expense rates in the U.S. segment due to lower operational activity and cost management efforts
Reduced our general and administrative expenses, primarily a result of broad-based cost saving measures, including temporary base salary reductions for CEO and other corporate officers through year-end, a reduction in Board of Director compensation through year-end, and U.S. employee and contractor workforce reductions.
Financial and operational results
Total net sales volumes for the year were 383 mboed, including 306 mboed in the U.S. Our U.S. net sales volumes decreased 5% and our wells to sales decreased 51% compared to 2019 as a result of lower drilling activity and natural field decline. We drilled and completed fewer wells in direct response to lower market prices.
Our net loss per share was $1.83 in 2020 as compared to a net income per share of $0.59 last year.
Items that contributed to the increase in our net loss in 2020, as compared to 2019, include:
A decrease in revenues of approximately 39% compared to 2019, as a result of decreased commodity price realizations and lower net sales volumes. The combination of lower prices and lower volumes was the single largest contributor to our net loss in 2020.
A loss from our equity method investments totaling $161 million, primarily due to $171 million of cumulative impairments in 2020 of an investment in an equity method investee; our 2019 income from equity method investments totaled $87 million.
An increase in exploration and impairment expenses of $152 million, primarily a result of non-cash impairment charges related to goodwill and certain proved and unproved properties in our REx portfolio. See Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements for further detail.
A lower income tax benefit of $74 million. The larger tax benefit in 2019 is primarily related to the settlement of the 2010-2011 IRS Audit in the first quarter of 2019. The tax benefit for 2020 was negligible due to no federal tax benefit on the U.S. loss due to the valuation allowance on our net federal deferred tax assets in the U.S. See Consolidated Results of Operations: 2020 compared to 2019 section below and Item 8. Financial Statements and Supplementary Data – Note 8 to the consolidated financial statements for further detail.
Items that partially offset the above include:
A gain on commodity derivatives of $116 million, compared to a net loss of $72 million in 2019.
A decline in production expense of $157 million and general and administrative expense of $82 million as discussed above.
Compensation and ESG Highlights and Initiatives
CEO and Board of Director total compensation reduced by approximately 25% with Board compensation mix shifted more toward equity and CEO mix further aligned with broader industry norms, exclusive of temporary reductions announced in 2020.
Achieved second consecutive year of record safety performance in 2020, as measured by total recordable incident rate (TRIR) for both employees and contractors.
Short-term incentive scorecard for compensation updated to focus on safety, environmental performance, capital efficiency, capital discipline/free cash flow generation and financial/balance sheet strength.
Added a 2021 GHG emissions intensity target to short-term incentive scorecard.
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Outlook
In February 2021, we announced a 2021 Capital Budget of $1.0 billion, which is effectively a maintenance Capital Budget. We expect this maintenance-level Capital Budget will allow us to keep total company oil production in 2021 consistent with our fourth quarter 2020 exit rate. Our 2021 Capital Budget is consistent with our capital allocation framework that prioritizes corporate returns and free cash flow generation over production growth.
The 2021 Capital Budget is weighted towards the four U.S. resource plays with approximately 92% allocated to the Eagle Ford and Bakken. Our 2021 Capital Budget is disaggregated by reportable segment in the table below:
(In millions) Capital Budget
United States $ 979 
International and other corporate items 21 
Total Capital Budget $ 1,000 

Operations
    The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations section for a price-volume analysis for each of the segments.
Net Sales Volumes 2020 Increase
(Decrease)
2019 Increase
(Decrease)
2018
United States (mboed)
306  (5) % 323 % 298
International (mboed)(a)
77  (15) % 91 (25) % 122
Total (mboed)
383  (7) % 414 (1) % 420
(a)     We closed on the sale of our Libya subsidiary in the first quarter of 2018, our interest in the Atrush block in Kurdistan in the second quarter of 2019 and our U.K. business in the third quarter of 2019. See Item 8. Financial Statements and Supplementary Data Note 5 to the consolidated financial statements for further information on dispositions.
United States
Net sales volumes in the segment were lower during the year ended December 31, 2020. In the second quarter of 2020, we began the process of transitioning to a significantly lower level of drilling and completion activity across our domestic portfolio, with our remaining resources allocated primarily to the Bakken and Eagle Ford. As a result of the decreased drilling and completion activity, fewer wells were brought to sales resulting in a decline in production in 2020. The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
Net Sales Volumes 2020 Increase
(Decrease)
2019 Increase
(Decrease)
2018
 Equivalent Barrels (mboed)
Eagle Ford 99  (7) % 106  (2) % 108 
Bakken 105  % 103  23  % 84 
Oklahoma 66  (15) % 78  % 74 
Northern Delaware 27  (4) % 28  40  % 20 
Other United States 13  % (33) % 12 
Total United States 306  (5) % 323  % 298 
Sales Mix - U.S. Resource Plays - 2020 Eagle Ford Bakken Oklahoma Northern Delaware Total
Crude oil and condensate 61% 75% 26% 55% 58%
Natural gas liquids 18% 14% 30% 20% 19%
Natural gas 21% 11% 44% 25% 23%
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Drilling Activity - U.S. Resource Plays 2020 2019 2018
Gross Operated
Eagle Ford:
Wells drilled to total depth 88 127 123
Wells brought to sales 87 146 149
Bakken:
Wells drilled to total depth 63 73 78
Wells brought to sales 64 105 80
Oklahoma:
Wells drilled to total depth 9 68 55
Wells brought to sales 13 69 57
Northern Delaware:
Wells drilled to total depth 15 51 69
Wells brought to sales 19 54 52
Eagle Ford – In 2020, our net sales volumes were 99 mboed including oil sales of 61 mbbld. We brought 87 gross company-operated wells to sales in 2020 across Karnes, Atascosa and Gonzales counties. New well production provided strong initial production rates that partially offset the lower wells to sales and natural field decline.
Bakken – In 2020, our net sales volumes were 105 mboed, including oil sales of 79 mbbld. We brought 64 gross company-operated wells to sales in 2020. Improved gas capture efforts resulted in higher gas and NGL sales that offset the lower wells to sales.
Oklahoma – In 2020, our net sales volumes were 66 mboed including oil sales of 17 mbbld. We brought 13 gross company-operated wells to sales in 2020. During the second quarter, we suspended all drilling and completions operations in Oklahoma.
Northern Delaware – In 2020, our net sales volumes were 27 mboed including oil sales of 15 mbbld. We brought 19 gross company-operated wells to sales in 2020. During the second quarter, we suspended drilling and completions operations in Northern Delaware.
International
Net sales volumes in the segment were lower during the year ended December 31, 2020 primarily due to timing of E.G. liftings and natural field decline, coupled with the disposition of our U.K. business. The following table provides details regarding net sales volumes for our operations within this segment:
Net Sales Volumes 2020 Increase
(Decrease)
2019 Increase
(Decrease)
2018
Equivalent Barrels (mboed)
Equatorial Guinea 77  (9) % 85  (12) % 97 
United Kingdom(a)
—  (100) % (62) % 13 
Libya —  —  % —  (100) %
Other International —  (100) % (75) %
Total International 77  (15) % 91  (25) % 122 
Equity Method Investees
LNG (mtd)
4,289  (13) % 4,933  (15) % 5,805 
Methanol (mtd)
1,017  (6) % 1,082  (13) % 1,241 
Condensate and LPG (boed)
10,288  (7) % 11,104  (15) % 13,034 
(a)     Includes natural gas acquired for injection and subsequent resale.
Equatorial Guinea – Net sales volumes in 2020 were lower than 2019 primarily due to timing of liftings and natural field decline.
United Kingdom – During 2019, we closed on the sale of our U.K. business. See Note 5 to the consolidated financial statements for further information.
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Libya – During the first quarter of 2018, we closed on the sale of our subsidiary in Libya. See Note 5 to the consolidated financial statements for further information.
Equity Method Investees – Net sales volumes in 2020 are tied to the volumes in Equatorial Guinea which were lower in the current year as noted above.
Market Conditions
Crude oil and condensate and NGL benchmarks decreased in 2020 as compared to the same period in 2019. As a result, we experienced decreased price realizations associated with those benchmarks. Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, payment of dividends and funding of share repurchases. Commodity prices declined substantially in the first half of 2020 resulting from demand contraction related to the global pandemic and increased supply following the OPEC decision to increase production. A revised OPEC deal to reduce production was agreed in the early second quarter of 2020 and prices partially recovered through the end of the year. However, worldwide demand remains below pre-pandemic levels and we continue to expect commodity prices to remain volatile, which will affect our price realizations during 2021. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition – Critical Accounting Estimates for further discussion of how declines in these commodity prices could impact us.

United States
 The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for 2020, 2019 and 2018.
2020 Increase (Decrease) 2019 Increase (Decrease) 2018
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)
$ 35.93  (36) % $ 55.80  (12) % $ 63.11 
Natural gas liquids (per bbl)
11.28  (21) % 14.22  (42) % 24.54 
Natural gas (per mcf)(c)
1.77  (19) % 2.18  (18) % 2.65 
Benchmarks
WTI crude oil average of daily prices (per bbl)
$ 39.34  (31) % $ 57.04  (12) % $ 64.90 
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)(d)
39.95  (36) % 61.96
LLS crude oil average of daily prices (per bbl)(d)
70.04 
Mont Belvieu NGLs (per bbl)(e)
14.69  (18) % 17.81  (33) % 26.75 
Henry Hub natural gas settlement date average (per mmbtu)
2.08  (21) % 2.63  (15) % 3.09 
(a)Excludes gains or losses on commodity derivative instruments.
(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average price realizations by $2.14 per bbl and $0.67 per bbl for 2020 and 2019, and decreased average price realizations by $4.60 per bbl for 2018.
(c)Inclusion of realized gains (losses) on natural gas derivative instruments would have had a minimal impact on average price realizations for the periods presented.
(d)Benchmark change due to industry shift to MEH in the first quarter of 2019.
(e)Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.
Crude oil and condensate – Price realizations may differ from benchmarks due to the quality and location of the product.
Natural gas liquids – The majority of our sales volumes are at reference to Mont Belvieu prices.
Natural gas A significant portion of volumes are sold at bid-week prices, or first-of-month indices relative to our producing areas.  
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International
The following table presents our average price realizations and the related benchmark for crude oil for 2020, 2019 and 2018.
2020 Increase (Decrease) 2019 Increase (Decrease) 2018
Average Price Realizations
Crude oil and condensate (per bbl)
$ 28.36  (47) % $ 53.09  (17) % $ 64.25 
Natural gas liquids (per bbl)
1.00  (29) % 1.40  (38) % 2.27 
Natural gas (per mcf)
0.24  (27) % 0.33  (39) % 0.54 
Benchmark
Brent (Europe) crude oil (per bbl)(a)
$ 41.76  (35) % $ 64.36  (9) % $ 71.06 
(a)    Average of monthly prices obtained from the United States Energy Information Agency website.

United Kingdom
Crude oil and condensate Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. business on July 1, 2019.
Equatorial Guinea
Crude oil and condensate Alba field liquids production is primarily condensate and generally sold in relation to the Brent crude benchmark. Alba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba field under a
fixed-price long-term contract. Alba Plant LLC extracts NGLs and secondary condensate which is then sold by Alba Plant LLC at market prices, with our share of the revenue reflected in income from equity method investments on the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas to the Alba field for distribution and sale to AMPCO and EG LNG.
Natural gas liquids Wet gas is sold to Alba Plant LLC at a fixed-price term contract resulting in realized prices not tracking market price. Alba Plant LLC extracts and keeps NGLs, which are sold at market price, with our share of income from Alba Plant LLC being reflected in the income from equity method investments on the consolidated statements of income.
Natural gas Dry natural gas, processed by Alba Plant LLC on behalf of the Alba field, is sold by the Alba field to EG LNG and AMPCO at fixed-price, long-term contracts resulting in realized prices not tracking market price. 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 long-term contract and AMPCO markets methanol at market prices.
Consolidated Results of Operations: 2020 compared to 2019
Revenues from contracts with customers are presented by segment in the table below:
Year Ended December 31,
(In millions) 2020 2019
Revenues from contracts with customers
United States $ 2,924  $ 4,602 
International 173  461 
Segment revenues from contracts with customers $ 3,097  $ 5,063 
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
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Increase (Decrease) Related to
(In millions) Year Ended December 31, 2019 Price Realizations Net Sales Volumes Year Ended December 31, 2020
United States Price/Volume Analysis
Crude oil and condensate $ 3,887  $ (1,285) $ (280) $ 2,322 
Natural gas liquids 307  (63) (1) 243 
Natural gas 349  (62) (12) 275 
Other sales 59  84 
Total $ 4,602  $ 2,924 
International Price/Volume Analysis
Crude oil and condensate $ 398  $ (122) $ (136) $ 140 
Natural gas liquids (1) — 
Natural gas 44  (10) (5) 29 
Other sales 14  — 
Total $ 461  $ 173 
Net gain (loss) on commodity derivatives in 2020 was a net gain of $116 million, compared to a net loss of $72 million in 2019. We have multiple crude oil, natural gas and NGL derivative contracts that settle against various indices. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 16 to the consolidated financial statements for further information.
Income (loss) from equity method investments decreased $248 million in 2020 from 2019 primarily due to impairments of $171 million to an investment in an equity method investee in 2020. In addition, lower price realizations and lower net sales volumes from equity method investments in E.G. contributed to the decrease, primarily due to AMPCO’s 2020 triennial turnaround, timing of liftings and natural field decline. See Item 8. Financial Statements and Supplementary Data – Note 24 to the consolidated financial statements for further information on the equity method investee impairment.
Net gain on disposal of assets decreased $41 million in 2020 from 2019, primarily as a result of the sale of our working interest in the Droshky field (Gulf of Mexico) and U.K. business in 2019. We had minimal disposal activity in 2020. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for information about these dispositions.
Other income decreased $37 million in 2020 from 2019 primarily due to income recognized in 2019 arising from indemnification payments received from Marathon Petroleum Corporation (“MPC”). Pursuant to the Tax Sharing Agreement we entered into with MPC in connection with the 2011 spin-off transaction, MPC agreed to indemnify us for certain liabilities. The indemnity relates to tax and interest allocable to MPC as a result of the closure of the 2010-2011 U.S. Federal Tax Audit in the first quarter of 2019.
Production expenses decreased $157 million during 2020 from 2019. Production expense in our United States segment decreased $94 million primarily due to lower operational activity and continued cost management, specifically staffing and contract labor. Production expense in our International segment decreased $67 million primarily as a result of the sale of our U.K. business and our non-operated interest in the Atrush block in Kurdistan in 2019.
The production expense rate (expense per boe) declined during 2020 in the United States and International segments due to the aforementioned reasons.
The following table provides production expense and production expense rates (expense per boe) for each segment:
(In millions; rate in $ per boe) 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Production Expense and Rate Expense Rate
United States $ 494  $ 588  (16) % $ 4.42  $ 4.98  (11) %
International $ 59  $ 126  (53) % $ 2.12  $ 3.76  (44) %
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Shipping, handling and other operating expenses decreased $9 million in 2020 from 2019 primarily as a result of lower net sales volumes in our United States segment, partially offset by higher marketing costs due to higher volumes purchased for resale in 2020.
 Exploration expenses include unproved property impairments, dry well costs, geological and geophysical and other, which increased $32 million during 2020 versus 2019. We impaired $78 million of unproved property leases in Louisiana Austin Chalk in our United States segment in 2020 due to a combination of factors, including our geological assessment, seismic information, timing of lease expiration dates and decisions not to develop acreage deemed non-core. This was partially offset by impairments of REx unproved leases in 2019, albeit lower than 2020, driven by our decision not to drill certain leases. See Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements for details of these items.
The following table summarizes the components of exploration expenses:
Year Ended December 31,
(In millions) 2020 2019 Increase (Decrease)
Exploration Expenses
Unproved property impairments $ 157  $ 98  60  %
Dry well costs 16  (88) %
Geological and geophysical 18  (67) %
Other 16  17  (6) %
Total exploration expenses $ 181  $ 149  21  %
Depreciation, depletion and amortization decreased $81 million in 2020 from 2019, primarily due to lower net sales volumes in the United States and E.G. along with the sale of our U.K. business in 2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per boe) is impacted by field-level changes in reserves, capitalized costs and sales volume mix between fields. The DD&A rate for International decreased primarily as a result of dispositions in 2019. The following table provides DD&A expense and DD&A expense rates for each segment:
(In millions; rate in $ per boe) 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
DD&A Expense and Rate Expense Rate
United States $ 2,211  $ 2,250  (2) % $ 19.76  $ 19.07  %
International $ 82  $ 121  (32) % $ 2.89  $ 3.61  (20) %
 Impairments increased $120 million in 2020 from 2019, primarily as a result of a $95 million goodwill charge related to our International reporting unit and a $49 million long-lived asset impairment related to a damaged, unsalvageable well and related equipment in the Louisiana Austin Chalk. See Item 8. Financial Statements and Supplementary Data – Note 12 for discussion of impairments in further detail.
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $111 million in 2020 from 2019 period primarily due to lower price realizations and lower sales volumes in the U.S. segment.
General and administrative expenses decreased $82 million in 2020 compared to 2019, which reflects costs savings realized from workforce reductions.
Provision (benefit) for income taxes reflects an effective income tax rate of 1% for 2020, as compared to an effective income tax rate of (22)% for 2019. See Item 8. Financial Statements and Supplementary Data – Note 8 to the consolidated financial statements for a discussion of the effective income tax rate.
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Segment Results: 2020 compared to 2019
    Segment Income
Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, impairments of proved and certain unproved properties, goodwill and equity method investments, certain exploration expenses relating to a strategic decision to exit conventional exploration, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, or other items (as determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
Year Ended December 31,
(In millions) 2020 2019 Increase (Decrease)
United States $ (553) $ 675  (182) %
International 30  233  (87) %
Segment income (loss) (523) 908  (158) %
Items not allocated to segments, net of income taxes(a)
(928) (428) (117) %
Net income (loss) $ (1,451) $ 480  (402) %
(a)    See Item 8. Financial Statements and Supplementary Data Note 7 to the consolidated financial statements for further detail about items not allocated to segments.
United States segment income (loss) in 2020 was an after-tax loss of $553 million versus after-tax income of $675 million in 2019, primarily as a result of lower crude price realizations and lower net sales volumes, which was partially offset by higher gain realized on commodity derivatives, and lower production taxes and production expenses.
 International segment income in 2020 was after-tax income of $30 million versus after-tax income of $233 million in 2019, primarily due to lower price realizations and sales volumes, partially offset by lower costs due to the sale of our U.K. business and our non-operated interest in the Atrush block in Kurdistan in 2019.
Consolidated Results of Operations: 2019 compared to 2018
    A detailed discussion of the year-over-year changes from the year ended December 31, 2019 to December 31, 2018 can be found in the Management’s Discussion and Analysis section of our Annual Report on Form 10-K for the year ended December 31, 2019 and is available via the SEC’s website at www.sec.gov and on our website at www.marathonoil.com.
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Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
Commodity prices are the most significant factor impacting our operating cash flows and the amount of capital available to reinvest into the business. In 2020, we experienced a decrease in operating cash flows primarily as a result of lower commodity price realizations, with crude oil and condensate price realizations decreasing by 36% to $35.39 per barrel. In direct response to the lower commodity prices, we reduced our 2020 Capital Budget such that the Capital Budget did not exceed cash provided by operations.
At December 31, 2020, we had approximately $3.7 billion of liquidity consisting of $742 million in cash and cash equivalents and $3.0 billion available under our Credit Facility. As previously discussed in the Outlook section, our Capital Budget for 2021 is $1.0 billion. Our top priorities for using cash provided by operations are to fund our Capital Budget and base dividend while also enhancing liquidity. We believe our current liquidity level, cash flow from operations and ability to access the capital markets provides us with the flexibility to fund our initiatives across a wide range of commodity price environments.
Cash Flows
The following table presents sources and uses of cash and cash equivalents for 2020 and 2019:
Year Ended December 31,
(In millions) 2020 2019
Sources of cash and cash equivalents    
Operating activities $ 1,473  $ 2,749 
Disposal of assets, net of cash transferred to the buyer 18  (76)
Borrowings 400  600 
Other 65 
Total sources of cash and cash equivalents $ 1,899  $ 3,338 
Uses of cash and cash equivalents
Additions to property, plant and equipment $ (1,343) $ (2,550)
Additions to other assets 15  36 
Acquisitions, net of cash acquired (1) (293)
Purchases of common stock (92) (362)
Debt repayments (500) (600)
Dividends paid (64) (162)
Other (30) (11)
Total uses of cash and cash equivalents $ (2,015) $ (3,942)
The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
Year Ended December 31,
(In millions) 2020 2019
United States $ 1,137  $ 2,550 
International 16 
Corporate 13  25 
Total capital expenditures