Dear fellow shareholders,
While 2020 was a challenging year for our industry, we are proud of our many accomplishments, especially
our record setting safety performance as we successfully managed through the ongoing COVID-19
pandemic as critical essential infrastructure providers.
During 2020, Marathon Oil took aggressive and decisive action in response to a challenging commodity
price and business environment. As a result, we successfully reduced our cash costs by more than 20%
compared to 2019, protected our investment grade balance sheet, meaningfully improved our GHG
emissions intensity, and ultimately generated sufficient free cash flow to fully fund $150 million of dividends
and share repurchases and $100 million of gross debt reduction.
We believe continuously improving all elements of our environmental, social, and governance (ESG)
performance is essential to successfully executing our long-term strategy of maximizing shareholder value,
including the delivery of strong financial returns and sustainable free cash flow while maintaining a solid
balance sheet and returning capital to shareholders.
Marathon Oil views safety as a core value and a key component of our ESG performance. During 2020, we
successfully managed through the ongoing COVID-19 pandemic with record setting safety performance,
as measured by a total recordable incident rate (TRIR). This was Marathon Oil’s second consecutive year
of record TRIR performance. Peer leading safety performance will remain a component of our executive
compensation scorecard.
During 2020, Marathon Oil made significant progress in improving environmental performance, achieving
a greater than 20% reduction in GHG emissions intensity relative to 2019 and improving total gas capture
to approximately 98.5% for fourth quarter 2020. For 2021, we established a quantitative GHG intensity
target, representing a reduction of more than 30% relative to 2019, which has been added to our executive
compensation scorecard. Further, Marathon Oil announced a medium-term goal to reduce GHG intensity
by at least 50% by 2025 relative to 2019, highlighting our commitment to significant ongoing improvement
to environmental performance.
In addition, we remain committed to best-in-class corporate governance with actions such as modifying
our executive compensation framework to enhance alignment with shareholders and incentivize
achievement of our core strategic objectives. Specifically, for 2021, we reduced annual Board compensation
by approximately 25% with the mix more heavily weighted toward equity, and reduced CEO total direct
compensation by 25%, including a 35% reduction to long-term incentive awards.
As we turn to 2021 and beyond, Marathon Oil remains committed to delivering strong corporate returns
and sustainable free cash flow. Marathon Oil announced a $1.0 billion capital expenditure budget for 2021
designed to continue prioritizing balance sheet enhancement and direct return of capital to investors,
including a targeted $500 million gross debt reduction in 2021.
Finally, we would like to thank all of our dedicated employees and contractors who made 2020 another
year of exceptional execution for our company.
Lee M. Tillman
Chairman, President and Chief Executive Officer
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
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
25-0996816
(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
Common Stock, par value $1.00
Trading Symbol
MRO
Name of each exchange on which registered
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
Items 1. and 2. Business and Properties
Item 1A.
Risk Factors
Unresolved Staff Comments
PART I
PART II
PART III
PART IV
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence Principal
Accountant Fees and Services
Exhibits, Financial Statement Schedules
Form 10-K Summary
SIGNATURES
Page
5
20
28
29
29
30
31
32
52
54
118
118
118
119
119
119
119
119
120
120
121
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.
1
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).
2
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.
3
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.
4
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.
Committed to our Framework
Corporate Returns
Disciplined reinvestment in strongest rate-of-return opportunities
Free Cash Flow
Sustainable free cash flow across wide range of commodity prices
Return of Capital
Return meaningful capital to investors
Differentiated Execution
Continuously improve performance, reduce costs, and deliver on
commitments
Powered by our Foundation
Multi-Basin Portfolio
Capital allocation flexibility, broad market access, supplier diversification,
rapid sharing of best practices, platform for talent development
Balance Sheet Strength
Continue improving investment grade balance sheet; maintain financial
strength and flexibility to execute business plan
ESG Excellence
Best-in-class governance, safe operations, strong environmental
performance, trusted partner to local communities
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
5
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:
6
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.
7
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.
Proved Developed Reserves
U.S.
E.G.
Total proved developed reserves (mmboe)
Proved Undeveloped Reserves
U.S.
E.G.
Total proved undeveloped reserves (mmboe)
Total Proved Reserves
U.S.
E.G.
Total proved reserves (mmboe)
Total proved reserves (%)
Crude Oil
and
Condensate
(mmbbl)
Natural Gas
Liquids
(mmbbl)
Natural Gas
(bcf)
Total
(mmboe)
Total
(%)
301
23
324
182
3
185
483
26
509
110
14
124
45
2
47
155
16
171
827
526
1,353
347
48
395
1,174
574
1,748
549
125
674
286
12
298
835
137
972
56 %
13 %
69 %
30 %
1 %
31 %
86 %
14 %
100 %
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.
E.G.
Total
2019
U.S.
E.G.
Total (a)
2018
U.S.
E.G.
Other International
Total
16
—
16
6
—
6
5,225
2,302
1,592
—
—
19
5,225
2,302
1,611
4,984
2,195
1,550
—
—
19
4,984
2,195
1,569
4,630
—
62
2,056
—
22
1,703
19
11
4,692
2,078
1,733
648
12
660
615
12
627
655
12
4
671
198
—
198
204
—
204
209
—
24
233
21
—
21
20
—
20
21
—
8
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.
Development
Oil
Natural Gas
Dry
Total Development
Exploratory
Oil
Natural Gas
Dry(a)
Total Exploratory
Total
December 31,
2020
2019
2018
103
15
—
118
30
14
—
44
162
197
28
—
225
57
26
2
85
310
171
25
—
196
66
36
3
105
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.
9
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.
(In thousands)
U.S.
E.G.
Total
Developed
Undeveloped
Developed and
Undeveloped
Gross
Net
Gross
Net
Gross
Net
1,380
82
993
67
1,462
1,060
306
—
306
247
1,686
1,240
—
82
67
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.
(In thousands)
U.S.
E.G.
Total
Net Undeveloped Acres Expiring
Year Ended December 31,
2021
2022
2023
94
—
94
48
—
48
94
—
94
10
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.
2020
December 31,
2019
2018
Net Sales Volumes
Crude oil and condensate (mbbld) (a)
United States
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Other U.S.
Africa
E.G.
Libya
Other International (b)
Total
Natural gas liquids (mbbld)
United States
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Other U.S.
Africa
E.G.
Total
Natural gas (mmcfd) (c)
United States
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Other U.S.
Africa
E.G.
Libya
Other International (b)
Total
Total sales volumes (mboed)
United States
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Other U.S.
Africa
E.G.
Libya
Other International (b)
Total
61
79
17
15
5
13
—
—
190
18
14
20
5
2
9
68
121
70
177
41
14
330
—
—
753
99
105
66
27
9
77
—
—
383
63
86
21
16
4
15
—
5
210
22
9
22
6
1
9
69
130
46
210
36
16
365
—
6
809
106
103
78
28
8
85
—
6
414
63
71
18
12
7
17
7
15
210
23
7
20
4
1
11
66
129
35
213
26
26
416
5
14
864
108
84
74
20
12
97
8
17
420
(a)
(b)
(c)
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid
hydrocarbons.
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.
Includes natural gas acquired for injection and subsequent resale.
11
Average Sales Price and Production Costs per Unit are presented by geographic area.
(Dollars per unit)
Average Sales Price per Unit (a)
Crude oil and condensate (bbl)
United States
Africa
E.G.
Libya
Total Africa
Other International (b)
Total
Natural gas liquids (bbl)
United States
Africa
E.G. (c)
Total Africa
Other International (b)
Total
Natural gas (mcf)
United States
Africa
E.G. (c)
Libya
Total Africa
Other International (b)
Total
Average Production Costs per Unit (d)
U.S.
E.G.
Libya
Other International (b)
Total
2020
December 31,
2019
2018
$
35.93
$
55.80
$
63.11
28.36
—
28.36
—
35.39
11.28
1.00
1.00
—
9.97
1.77
0.24
—
0.24
—
1.10
8.40
2.16
—
—
7.15
$
$
$
$
$
$
$
48.99
—
48.99
64.71
55.54
14.22
1.00
1.00
37.88
12.46
2.18
0.24
—
0.24
5.67
1.33
9.08
2.34
—
30.42
8.03
$
$
$
$
$
$
$
55.28
73.75
60.65
70.39
63.32
24.54
1.00
1.00
41.66
20.85
2.65
0.24
4.57
0.30
8.03
1.58
9.83
1.91
4.35
30.02
8.68
$
$
$
$
$
$
$
(a)
(b)
(c)
(d)
Excludes gains or losses on commodity derivative instruments.
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.
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.
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.
12
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:
Eagle Ford
Crude and condensate (mbbld)
Natural gas (mmcfd)
Bakken
Crude and condensate (mbbld)
Natural gas (mmcfd)
Other United States
Natural gas (mmcfd)
2021
2022
2023
Thereafter
Commitment
Period Through
33
148
21
14
4
—
128
12
—
1
—
92
10
—
—
—
12
5 - 10
—
—
2021
2025
2027
2021
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
13
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.
14
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 a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation
matters, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies
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.
15
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.
16
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.
17
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
Dane E. Whitehead
Patrick J. Wagner
Mike Henderson
Kimberly O. Warnica
Gary E. Wilson
59
59
56
51
47
59
Chairman, President and Chief Executive Officer
Executive Vice President—Chief Financial Officer
Executive Vice President—Corporate Development and Strategy
Senior Vice President—Operations
Senior Vice President—General Counsel
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.
18
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:
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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:
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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:
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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:
WTI crude oil (per bbl)
Henry Hub natural gas (per mmbtu)
Brent crude oil (per bbl)
Mont Belvieu NGLs (per bbl)
2020 SEC Pricing
$
$
$
$
39.57
1.99
41.77
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:
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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:
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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:
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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:
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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:
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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
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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:
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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
27
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.
28
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.
29
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:
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)
Period
10/01/2020 - 10/31/2020
11/01/2020 - 11/30/2020
12/01/2020 - 12/31/2020
Total
22,423 $
— $
1,162 $
23,585 $
3.95
—
5.86
4.05
Approximate Dollar
Value of Shares that May
Yet Be Purchased Under
the Plans or Programs(b)
1,320,335,751
— $
— $
— $
—
1,320,335,751
1,320,335,751
(a)
(b)
23,585 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
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.
30
Item 6. Selected Financial Data
(In millions, except per share data)
Statement of Income Data(a)
Total revenues and other income
Income (loss) from continuing operations
Discontinued operations(b)
Net income (loss)
Per Share Data(a)
Basic:
Income (loss) from continuing operations
Discontinued operations(b)
Net income (loss)
Diluted:
Income (loss) from continuing operations
Discontinued operations(b)
Net income (loss)
Statement of Cash Flows Data
Additions to property, plant and equipment related to
continuing operations
Dividends paid
Dividends per share
Balance Sheet Data at December 31
Total assets
Total long-term debt, including capitalized leases
Leases:(c)
Right-of-use asset
Current portion of long-term lease liability
Long-term lease liability
Year Ended December 31,
2020
2019
2018
2017
2016
3,086 $
5,190 $
6,582 $
4,765 $
3,787
(1,451) $
480 $
1,096 $
(830) $
(2,087)
— $
— $
— $
(4,893) $
(53)
(1,451) $
480 $
1,096 $
(5,723) $
(2,140)
(1.83) $
0.59 $
1.30 $
(0.97) $
— $
— $
— $
(5.76) $
(1.83) $
0.59 $
1.30 $
(6.73) $
(1.83) $
— $
(1.83) $
0.59 $
— $
0.59 $
1.29 $
— $
(0.97) $
(5.76) $
1.29 $
(6.73) $
(2.55)
(0.06)
(2.61)
(2.55)
(0.06)
(2.61)
(1,343) $
(2,550) $
(2,753) $
(1,974) $
(1,204)
(64) $
(162) $
(169) $
(170) $
0.08 $
0.20 $
0.20 $
0.20 $
(162)
0.20
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 17,956 $ 20,245 $ 21,321 $ 22,012 $ 31,094
$
5,404 $
5,501 $
5,499 $
5,494 $
6,581
$
$
$
133 $
70 $
67 $
199 $
101 $
107 $
— $
62 $
155 $
— $
29 $
90 $
—
30
146
December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million.
(a)
(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.
(In millions)
Proved property impairment
Unproved property impairment
Goodwill impairment
Equity method investment impairment
Year Ended December 31,
2020
2019
2018
2017
2016
$
$
$
$
49 $
157 $
95 $
171 $
24 $
98 $
— $
— $
75 $
208 $
— $
— $
229 $
246 $
— $
— $
67
195
—
—
31
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.
32
•
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.
33
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)
United States
International and other corporate items
Total Capital Budget
Operations
$
$
Capital Budget
979
21
1,000
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
United States (mboed)
International (mboed)(a)
2020
306
77
Increase
(Decrease)
(5) %
(15) %
2019
Increase
(Decrease)
2018
323
91
8 %
(25) %
298
122
Total (mboed)
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
(7) %
(1) %
383
414
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
Equivalent Barrels (mboed)
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Other United States
Total United States
2020
Increase
(Decrease)
2019
Increase
(Decrease)
2018
99
105
66
27
9
306
(7) %
2 %
(15) %
(4) %
13 %
(5) %
106
103
78
28
8
323
(2) %
23 %
5 %
40 %
(33) %
8 %
108
84
74
20
12
298
Sales Mix - U.S. Resource Plays - 2020
Eagle Ford
Bakken
Oklahoma
Crude oil and condensate
Natural gas liquids
Natural gas
75%
14%
11%
26%
30%
44%
61%
18%
21%
34
Northern
Delaware
55%
20%
25%
Total
58%
19%
23%
Drilling Activity - U.S. Resource Plays
Gross Operated
2020
2019
2018
Eagle Ford:
Wells drilled to total depth
Wells brought to sales
Bakken:
Wells drilled to total depth
Wells brought to sales
Oklahoma:
Wells drilled to total depth
Wells brought to sales
Northern Delaware:
Wells drilled to total depth
Wells brought to sales
88
87
63
64
9
13
15
19
127
146
73
105
68
69
51
54
123
149
78
80
55
57
69
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
Equivalent Barrels (mboed)
Equatorial Guinea
United Kingdom(a)
Libya
Other International
Total International
Equity Method Investees
LNG (mtd)
Methanol (mtd)
Condensate and LPG (boed)
2020
Increase
(Decrease)
2019
Increase
(Decrease)
2018
77
—
—
—
77
(9) %
(100) %
— %
(100) %
(15) %
85
5
—
1
91
(12) %
(62) %
(100) %
(75) %
(25) %
97
13
8
4
122
4,289
1,017
10,288
(13) %
(6) %
4,933
1,082
(15) %
(13) %
5,805
1,241
(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.
35
•
•
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.
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)
Natural gas liquids (per bbl)
Natural gas (per mcf)(c)
Benchmarks
2020
Increase
(Decrease)
2019
Increase
(Decrease)
2018
$ 35.93
(36) % $ 55.80
(12) % $ 63.11
11.28
1.77
(21) %
14.22
(42) %
24.54
(19) %
2.18
(18) %
2.65
WTI crude oil average of daily prices (per bbl)
Magellan East Houston (“MEH”) crude oil average of daily
prices (per bbl)(d)
LLS crude oil average of daily prices (per bbl)(d)
Mont Belvieu NGLs (per bbl)(e)
Henry Hub natural gas settlement date average (per mmbtu)
$ 39.34
(31) % $ 57.04
(12) % $ 64.90
39.95
(36) %
61.96
14.69
2.08
(18) %
17.81
(21) %
2.63
(33) %
(15) %
70.04
26.75
3.09
(a)
(b)
(c)
(d)
(e)
Excludes gains or losses on commodity derivative instruments.
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.
Inclusion of realized gains (losses) on natural gas derivative instruments would have had a minimal impact on average price realizations for the periods
presented.
Benchmark change due to industry shift to MEH in the first quarter of 2019.
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.
36
International
The following table presents our average price realizations and the related benchmark for crude oil for 2020, 2019 and
2018.
Average Price Realizations
Crude oil and condensate (per bbl)
Natural gas liquids (per bbl)
Natural gas (per mcf)
Benchmark
Brent (Europe) crude oil (per bbl)(a)
2020
Increase
(Decrease)
2019
Increase
(Decrease)
2018
$ 28.36
(47) % $ 53.09
(17) % $ 64.25
1.00
0.24
(29) %
(27) %
1.40
0.33
(38) %
(39) %
2.27
0.54
$ 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:
(In millions)
Revenues from contracts with customers
United States
International
Segment revenues from contracts with customers
Year Ended December 31,
2020
2019
$
$
2,924 $
173
3,097 $
4,602
461
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.
37
(In millions)
United States Price/Volume Analysis
Crude oil and condensate
Natural gas liquids
Natural gas
Other sales
Total
International Price/Volume Analysis
Crude oil and condensate
Natural gas liquids
Natural gas
Other sales
Total
Increase (Decrease) Related to
Year Ended
December 31, 2019
Price
Realizations
Net Sales
Volumes
Year Ended
December 31, 2020
$
$
$
$
3,887 $
(1,285) $
(280) $
307
349
59
4,602
(63)
(62)
(1)
(12)
$
398 $
(122) $
(136) $
5
44
14
461
(1)
(10)
—
(5)
$
2,322
243
275
84
2,924
140
4
29
—
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)
Production Expense and Rate
United States
International
2020
2019
Expense
Increase
(Decrease)
2020
Increase
(Decrease)
2019
Rate
$
$
494 $
59 $
588
126
(16) % $
4.42 $
(53) % $
2.12 $
4.98
3.76
(11) %
(44) %
38
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:
(In millions)
Exploration Expenses
Unproved property impairments
Dry well costs
Geological and geophysical
Other
Total exploration expenses
Year Ended December 31,
2020
2019
Increase
(Decrease)
$
$
157 $
2
6
16
181 $
98
16
18
17
149
60 %
(88) %
(67) %
(6) %
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)
DD&A Expense and Rate
United States
International
2020
2019
Expense
Increase
(Decrease)
2020
Increase
(Decrease)
2019
Rate
$ 2,211 $ 2,250
(2) % $ 19.76 $
19.07
$
82 $
121
(32) % $
2.89 $
3.61
4 %
(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.
39
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):
(In millions)
United States
International
Segment income (loss)
Items not allocated to segments, net of income taxes(a)
Year Ended December 31,
2020
2019
Increase
(Decrease)
$
(553) $
30
(523)
(928)
675
233
908
(428)
480
(182) %
(87) %
(158) %
(117) %
(402) %
Net income (loss)
$
(1,451) $
(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.
40
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:
(In millions)
Sources of cash and cash equivalents
Operating activities
Disposal of assets, net of cash transferred to the buyer
Borrowings
Other
Total sources of cash and cash equivalents
Uses of cash and cash equivalents
Additions to property, plant and equipment
Additions to other assets
Acquisitions, net of cash acquired
Purchases of common stock
Debt repayments
Dividends paid
Other
Year Ended December 31,
2020
2019
$
$
$
1,473 $
2,749
18
400
8
(76)
600
65
1,899 $
3,338
(1,343) $
(2,550)
15
(1)
(92)
(500)
(64)
(30)
36
(293)
(362)
(600)
(162)
(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:
(In millions)
United States
International
Corporate
Total capital expenditures
Change in capital expenditure accrual
Year Ended December 31,
2020
2019
$
1,137 $
2,550
1
13
1,151
192
16
25
2,591
(41)
2,550
Total use of cash and cash equivalents for property, plant and equipment
$
1,343 $
During the third and fourth quarters of 2020, we completed two separate financing transactions resulting in a remarketing
of $400 million of sub-series B bonds to investors and a separate debt repayment of $500 million, which is further discussed in
the Capital Resources section below. Also see Item 8. Financial Statements and Supplementary Data – Note 18 to the
consolidated financial statements for details of these transactions.
41
During the first quarter of 2020, the Board of Directors approved a $0.05 per share dividend. The Board of Directors
temporarily suspended our quarterly dividend payment in the second quarter as we prioritized liquidity and our balance sheet
given the macro environment. During the fourth quarter of 2020, the Board of Directors approved the reinstatement of the
dividend and declared a base quarterly dividend of $0.03 per share. During 2019, the Board of Directors approved a $0.05 per
share dividend each quarter.
Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-
core assets, capital market transactions and our revolving Credit Facility. 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 revolving Credit
Facility. See Item 8. Financial Statements and Supplementary Data – Note 26 to the consolidated financial statements for a
further discussion of how our commitments and contingencies could affect our available liquidity.
Our working capital requirements are supported by our cash and cash equivalents and our Credit Facility. We may draw on
our revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf
registration statement discussed below as part of our longer-term liquidity and capital management program. Because of the
alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not
only our current operations, but also our near-term and long-term funding requirements including our capital spending
programs, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may
ultimately be paid in connection with contingencies. General economic conditions, commodity prices and financial, business
and other factors, including the global pandemic, could affect our operations and our ability to access the capital markets.
During the first half of 2020, commodity prices significantly declined due to the combined impacts of global crude oil
oversupply and lower demand for hydrocarbons due to the global pandemic. As a result, credit rating agencies reviewed many
companies in the industry, including us. We continue to be rated investment grade at all three primary credit rating agencies. A
downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and could result
in additional credit support requirements. See Item 1A. Risk Factors for a discussion of how a downgrade in our credit ratings
could affect us.
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 could increase the risk that our liquidity and financial
flexibility deteriorates. See Item 1A. Risk Factors for a further discussion of how our level of indebtedness could affect us.
Capital Resources
Credit Arrangements and Borrowings
As of December 31, 2020, we had no borrowings on our $3.0 billion Credit Facility. At December 31, 2020, we had $5.4
billion of total debt outstanding. In October 2020, we completed a cash tender offer for an aggregate principal amount of $500
million of our then-outstanding $1 billion 2.8% senior notes due 2022. Our next significant debt maturity is the remaining $500
million 2.8% senior notes that are due in November 2022. We do not have any triggers on any of our corporate debt that would
cause an event of default in the case of a downgrade of our credit ratings.
On August 18, 2020, we closed a $400 million remarketing to investors of sub-series B bonds which are part of the $1.0
billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017.
Information about these bonds are available on the website of the Municipal Securities Rulemaking Board via its Electronic
Municipal Market Access system at www.msrb.org. Information on that website is not incorporated by reference into this filing.
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in
Houston, Texas. The lessor and other participants are providing financing for up to $340 million to fund the estimated project
costs, which was reduced effective August 2020 from $380 million to align with our revised estimate of the project costs. As of
December 31, 2020, project costs incurred totaled approximately $144 million, including land acquisition and construction
costs.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a “well-known seasoned issuer” for
purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
42
Debt-To-Capital Ratio
The Credit Facility includes a single financial covenant requiring that our ratio of total debt to total capitalization not
exceed 65% as of the last day of each fiscal quarter. This covenant calculation was modified in December 2020, when we
executed the fifth amendment to our credit facility. The primary changes resulting from this amendment are (i) a modification
to the debt to total capitalization covenant calculation that permits an add-back to shareholders’ equity for certain non-cash
write-downs, (ii) the addition of certain customary events of default, including a cross payment event of default and (iii) certain
restrictions on the incurrence of subsidiary indebtedness. Under the amended definition, our total debt to total capitalization
ratio was 26% at December 31, 2020.
Capital Requirements
Capital Spending
Our approved Capital Budget for 2021 is $1.0 billion. Additional details were previously discussed in Outlook.
Share Repurchase Program
In 2020, we acquired approximately 9 million common shares at a cost of $85 million under our share repurchase program.
While the share repurchase program remains approved and has $1.3 billion of remaining authorization, we elected to suspend
additional share repurchases to preserve liquidity.
On January 27, 2021, our Board of Directors approved a dividend of $0.03 per share for the fourth quarter of 2020. The
dividend is payable on March 10, 2021 to shareholders of record on February 17, 2021.
We plan to make contributions of up to $40 million to our funded pension plans during 2021. Cash contributions to be paid
from our general assets for the unfunded pension and postretirement plans are expected to be approximately $3 million and $10
million in 2021.
43
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing
contracts as of December 31, 2020.
(In millions)
Short and long-term debt (includes interest)(a)
Lease obligations
Purchase obligations:
Oil and gas activities(b)
Service and materials contracts(c)
Transportation and related contracts
Other (d)
Total purchase obligations
Other long-term liabilities reported in the
consolidated balance sheet(e)
Total contractual cash obligations(f)
Total
2021
2022-
2023
2024-
2025
Later
Years
$
7,985 $
247 $
1,407 $
1,691 $
4,640
287
26
53
1,555
19
1,653
316
77
16
31
208
19
274
31
55
2
21
445
—
468
55
9
1
1
405
—
407
48
146 (g)
7
—
497
—
504
182
$
10,241 $
629 $
1,985 $
2,155 $
5,472
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Includes anticipated cash payments for interest of $247 million for 2021, $471 million for 2022-2023, $391 million for 2024-2025 and $1.4 billion for the
remaining years for a total of $2.5 billion.
Includes contracts to acquire property, plant and equipment and commitments for oil and gas drilling and completion activities.
Includes contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
Includes any drilling rigs and fracturing crews that are not considered lease obligations.
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding
requirements through 2027. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent
potential demands on our liquidity.
This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $254
million. See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements.
Includes $144 million of project costs incurred as of December 31, 2020 for a new build-to-suit office building in Houston, Texas. See Item 8. Financial
Statements and Supplementary Data – Note 14 to the consolidated financial statements and Off-Balance Sheet Arrangements section below.
Transactions with Related Parties
Offshore E.G, we own a 63% working interest in the Alba field. Onshore E.G., we own a 52% interest in an LPG
processing plant, a 60% interest in an LNG production facility and a 45% interest in a methanol production plant, each through
equity method investees. We sell our natural gas from the Alba field to these equity method investees as the feedstock for their
production processes.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources
and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally
accepted in the U.S. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on
these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are
reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital
resources.
We will issue stand-alone letters of credit when required by a business partner. Such letters of credit outstanding at
December 31, 2020, 2019 and 2018 aggregated $14 million, $14 million and $52 million. Most of the letters of credit are in
support of obligations recorded in the consolidated balance sheet. In 2019, our letters of credit outstanding decreased as a result
of our upgraded credit rating and the sale of our U.K. business (we no longer have requirements to support firm transportation
agreements and future abandonment liabilities).
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in
Houston, Texas. The lessor and other participants are providing financing for up to $340 million, to fund the estimated project
costs, which was reduced effective August 2020, from $380 million to align with our revised estimate of the project costs. As of
December 31, 2020 project costs incurred totaled $144 million, primarily for land acquisition and initial design costs. The
initial lease term is five years and will commence once construction is substantially complete and the new Houston office is
ready for occupancy. At the end of the initial lease term, we can extend the term of the lease for an additional five years, subject
44
to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an
unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and
construction costs. See Item 8. Financial Statements and Supplementary Data – Note 14 to the consolidated financial statements
for further information on leases.
Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies
We have incurred and will continue to incur capital, operating and maintenance and remediation expenditures as a result of
environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices of our
products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must
comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending
on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
These laws generally provide for control of pollutants released into the environment and require responsible parties to
undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of
associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as
additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future on
both state and federal levels. We strive to comply with all legal requirements regarding the environment, but as not all costs are
fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is
not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties
that may be imposed.
For more information on environmental regulations that impact us, or could impact us, see Item 1. Business –
Environmental, Health and Safety Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings.
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us
to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent
assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses
during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and
assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the
susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating
performance is material. Actual results could differ from the estimates and assumptions used.
Estimated Quantities of Net Reserves
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method
inherently relies on the estimation of proved crude oil and condensate, NGLs and natural gas reserves. The amount of estimated
proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of
costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas
producing activities. In addition, the expected future cash flows to be generated by producing properties are used for testing
impairment and the expected future taxable income available to realize deferred tax assets, also in part, rely on estimates of
quantities of net reserves. Refer to the applicable sections below for further discussion of these accounting estimates.
The estimation of quantities of net reserves is a highly technical process performed by our petroleum engineers and
geoscientists for crude oil and condensate, NGLs and natural gas, which is based upon several underlying assumptions. The
reserve estimates may change as additional information becomes available and as contractual, operational, economic and
political conditions change. We evaluate our reserves using drilling results, reservoir performance, subsurface interpretation and
future plans to develop acreage. Technologies used in proved reserves estimation includes statistical analysis of production
performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and
volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity
or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty
criteria required for booking proved reserves. As per SEC requirements, proved undeveloped reserve volumes are limited to
activity in the 5-year plan and wells that will be developed within 5 years of initial booking. The data for a given reservoir may
also change over time as a result of numerous factors including, but not limited to, additional development activity and future
development costs, production history and continual reassessment of the viability of future production volumes under varying
economic conditions.
45
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using
the closing prices on the first day of each month, as defined by the SEC. The table below provides the 2020 SEC pricing for
certain benchmark prices:
WTI crude oil (per bbl)
Henry Hub natural gas (per mmbtu)
Brent crude oil (per bbl)
Mont Belvieu NGLs (per bbl)
2020 SEC Pricing
$
$
$
$
39.57
1.99
41.77
14.41
When determining the December 31, 2020 proved reserves for each property, the benchmark prices listed above were
adjusted using price differentials that account for property-specific quality and location differences.
If the future average crude oil prices are below the average 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. It is
difficult to estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors
(including future crude oil price and performance revisions). For further discussion of risks associated with our estimation of
proved reserves, see Part I. Item 1A. Risk Factors.
Depreciation and depletion of crude oil and condensate, NGLs and natural gas producing properties is determined by the
units-of-production method and could change with revisions to estimated proved reserves. While revisions of previous reserve
estimates have not historically been significant to the depreciation and depletion rates of our segments, any reduction in proved
reserves, could result in an acceleration of future DD&A expense. The following table illustrates, on average, the sensitivity of
each segment’s units-of-production DD&A per boe and pretax income to a hypothetical 10% change in 2020 proved reserves
based on 2020 production.
(In millions, except per boe)
DD&A per boe
Pretax Income
DD&A per boe
Pretax Income
Impact of a 10% Increase in
Proved Reserves
Impact of a 10% Decrease in
Proved Reserves
United States
International
Fair Value Estimates
$
$
(1.80) $
(0.26) $
201 $
7 $
2.20 $
0.32 $
(246)
(9)
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities:
the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The
market approach uses prices and other relevant information generated by market transactions involving identical or comparable
assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as
cash flows or earnings, into a single present value, or range of present values, using current market expectations about those
future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an
asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what
it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value
and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in
applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing
decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level
3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
•
•
•
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of
the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient
frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs
other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the
measurement date.
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed
methodologies that result in management’s best estimate of fair value.
46
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their
entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the
significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and
liabilities within the levels of the fair value hierarchy. See Item 8. Financial Statements and Supplementary Data – Note 17 to
the consolidated financial statements for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
assets and liabilities acquired in a business combination;
assets acquired in an asset acquisition;
impairment assessments of long-lived assets;
impairment assessments of equity method investments;
impairment assessments of goodwill;
recorded value of derivative instruments; and
recorded value of pension plan assets.
•
•
•
•
•
•
•
The need to test long-lived assets and goodwill for impairment can be based on several indicators, including a significant
reduction in prices of crude oil and condensate, NGLs and natural gas, sustained declines in our common stock, reductions to
our Capital Budget, unfavorable adjustments to reserves, significant changes in the expected timing of production, other
changes to contracts or changes in the regulatory environment in which the property is located.
Impairment Assessments of Long-Lived Assets
Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the
carrying value of the assets may not be recoverable. For purposes of an impairment evaluation, long-lived assets must be
grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field or, in certain
instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic
interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset
group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the
estimated fair value.
Fair value calculated for the purpose of testing our long-lived assets for impairment is estimated using the present value of
expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in
performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:
•
•
•
•
•
Future crude oil and condensate, NGLs and natural gas prices. Our estimates of future prices are based on our analysis
of market supply and demand and consideration of market price indicators. Although these commodity prices may
experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply
and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates
and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and
income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent
with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and
condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk
Factors for further discussion on commodity prices.
Estimated quantities of crude oil and condensate, NGLs and natural gas. Such quantities are based on a combination of
proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most
likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.
Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves, as
well as expected capital programs. The actual timing of the production could be different than the projection. Cash flows
realized later in the projection period are less valuable than those realized earlier due to the time value of money. The
expected timing of production that we use in our fair value estimates is consistent with that used in our planning and
capital investment reviews.
Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a
variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher
discount rate decreases the net present value of cash flows.
Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized
spending and internal forecasts.
47
We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An
estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the
numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating
costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable
adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For
example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset
by lower costs. As of December 31, 2020 our estimated undiscounted cash flows relating to our remaining long-lived assets
significantly exceeded their carrying values.
During 2020, we recorded impairment charges totaling $133 million related to proved and certain unproved properties. See
Item 8. Financial Statements and Supplementary Data Note 12 and Note 17 to the consolidated financial statements for
discussion of impairments recorded in 2020, 2019 and 2018 and the related fair value measurements.
Impairment Assessment of Equity Method Investments
During 2020, we recorded impairment charges totaling $171 million pertaining to an investment in an equity method
investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income.
Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in
value may have occurred. When a loss is deemed to have occurred that is other than temporary, the carrying value of the equity
method investment is written down to fair value.
Fair value calculated for the purpose of testing our equity method investees for impairment is estimated using the present
value of expected future cash flows method. Significant judgment is involved in performing these fair value estimates since the
results are based on forecasted assumptions and the performance of entities that we do not control. Significant assumptions
include:
•
•
•
•
Future condensate, NGL, LNG, natural gas and methanol prices. Our estimates of future prices are based on our
analysis of market supply and demand and consideration of market price indicators. Although these commodity prices
may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market
supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base,
depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such
as population and income growth, and governmental policies. The prices we use in our fair value estimates are
consistent with those used in our planning and capital investment reviews. There has been significant volatility in
commodity prices and estimates of such future prices are inherently imprecise.
Estimated quantities of feedstock condensate, NGLs and natural gas processed by our investees. There are two primary
sets of inputs used to estimate feedstock volumes processed by our investees. The first input involves hydrocarbons
produced from our Alba Field. Our equity method investees currently process hydrocarbons from our Alba Field,
which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from
our Alba Field are based on a combination of proved reserves and risk-weighted probable reserves and resources such
that the combined volumes represent the most likely expectation of recovery.
The second input involves our estimate of future third-party gas to be processed by our investees. Our investees have
capacity to process hydrocarbons from sources other than our Alba field. During 2019, we executed agreements for
processing natural gas produced from the third party-owned Alen Unit through the existing Alba Plant LLC LPG
processing plant and the EGHoldings LNG production facility beginning in 2021. Estimated natural gas volumes
processed from the Alen Unit were based on forecasts received from the operator of the Alen Unit.
Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves,
as well as expected capital programs. The actual timing of the production could be different than the projection. Cash
flows realized later in the projection period are less valuable than those realized earlier due to the time value of money.
The expected timing of production from the Alba Field that we use in our fair value estimates is consistent with that
used in our planning and capital investment reviews. The expected timing of production from the Alen Unit is
consistent with forecasts received from the operator of that field.
Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a
variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A
higher discount rate decreases the net present value of cash flows.
We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. This
includes the estimated dividends and/or return of capital we expect to be paid by our equity method investees, which are
directly affected by the significant assumptions described in the preceding paragraphs. An estimate of the sensitivity to changes
48
in assumptions in our cash flow calculations is not practicable, given the numerous other assumptions (e.g. reserves, commodity
prices, operating costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some
of the above listed assumptions would likely be offset by favorable adjustments in other assumptions.
See Note 12 to the consolidated financial statements for further information regarding the impairment recognized during
2020.
Impairment Assessments of Goodwill
Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances
indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit
level. Our reporting units are the same as our reporting segments, of which historically only International included goodwill.
Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Our
policy is to first assess the qualitative factors in order to determine whether the fair value of our International reporting unit is
more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other
things, the results of the most recent quantitative assessment of the goodwill impairment test; macroeconomic conditions;
industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant
entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not that the
fair value of the International reporting unit is less than its carrying amount, a quantitative goodwill test is performed. The
quantitative goodwill test is performed using a combination of market and income approaches. The market approach references
observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value and valuation
multiples of us and our peers from the investor analyst community. The income approach utilizes discounted cash flows, which
are based on forecasted assumptions. Key assumptions to the income approach are the same as those described above regarding
our impairment assessment of long-lived assets and are consistent with those that management uses to make business decisions.
In the first quarter of 2020, a triggering event (significant decline in market capitalization caused by worldwide declines in
hydrocarbon demand and corresponding prices) required us to assess our goodwill in the International reporting unit for
impairment as of March 31, 2020. We estimated the fair value of our International reporting unit using a combination of market
and income approaches and concluded that a full impairment of $95 million was required. See Item 8. Financial Statements and
Supplementary Data Note 15 to the consolidated financial statements for additional discussion of goodwill.
Derivatives
We record all derivative instruments at fair value. Fair value measurements for all our derivative instruments are based on
observable market-based inputs that are corroborated by market data and are discussed in Item 8. Financial Statements and
Supplementary Data – Note 16 to the consolidated financial statements. Additional information about derivatives and their
valuation may be found in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Pension Plan Assets
Pension plan assets are measured at fair value. See Item 8. Financial Statements and Supplementary Data – Note 20 to the
consolidated financial statements for discussion of the fair value of plan assets and the presentation of the fair value of our
defined benefit pension plan’s assets by level within the fair value hierarchy as of December 31, 2020 and 2019.
Income Taxes
We are subject to income taxes in numerous taxing jurisdictions worldwide. Estimates of income taxes to be recorded
involve interpretation of complex tax laws and assessment of the effects of foreign taxes on our U.S. federal income taxes.
Uncertainty exists regarding tax positions taken in previously filed tax returns which remain subject to examination, along
with positions expected to be taken in future returns. We provide for unrecognized tax benefits, based on the technical merits,
when it is more likely than not that an uncertain tax position will not be sustained upon examination. Adjustments are made to
the uncertain tax positions when facts and circumstances change, such as the closing of a tax audit; court proceedings; changes
in applicable tax laws, including tax case rulings and legislative guidance; or expiration of the applicable statute of limitations.
We have recorded deferred tax assets and liabilities, measured at enacted tax rates, for temporary differences between book
basis and tax basis, tax credit carryforwards and operating loss carryforwards. In accordance with U.S. GAAP accounting
standards, we routinely assess the realizability of our deferred tax assets and reduce such assets, to the expected realizable
amount, by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be
realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider all available positive
and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income,
assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative
49
evidence includes losses in recent years as well as the forecasts of future loss in the realizable period. In making our assessment
regarding valuation allowances, we weight the evidence based on objectivity.
We base our future taxable income estimates on projected financial information which we believe to be reasonably likely to
occur. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as
future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes. Future operating
conditions can be affected by numerous factors, including (i) future crude oil and condensate, NGLs and natural gas prices, (ii)
estimated quantities of crude oil and condensate, NGLs and natural gas, (iii) expected timing of production, and (iv) future
capital requirements. These assumptions are described in further detail above regarding our impairment assessment of long-
lived assets. An estimate of the sensitivity to changes in assumptions resulting in future taxable income calculations is not
practicable, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the
above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of
sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures.
Based on the assumptions and judgments described above, as of December 31, 2020, we reflect a valuation allowance in
our consolidated balance sheet of $948 million against our gross deferred tax assets of $2.7 billion in various jurisdictions in
which we operate. Our gross deferred tax assets consist primarily of federal U.S. operating loss carryforwards of $655 million,
which will expire in 2035 - 2037, and $1.1 billion which can be carried forward indefinitely. Since December 31, 2016, we
have maintained a full valuation allowance on our net federal deferred tax assets. If objective negative evidence in the form of
cumulative losses are no longer present and additional weight is given to subjective evidence such as forecasted projections of
taxable income in future years, we would adjust the amount of the federal deferred tax assets considered realizable and reduce
the provision for income taxes in the period of adjustment. See Item 8. Financial Statements and Supplementary Data – Note 8
to the consolidated financial statements for further detail.
Pension and Other Postretirement Benefit Obligations
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant
of which relate to the following:
•
•
•
the discount rate for measuring the present value of future plan obligations;
the expected long-term return on plan assets; and
the rate of future increases in compensation levels.
We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these
obligations. We have selected different discount rates for our U.S. pension plans and our other U.S. postretirement benefit plans
due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a
review of market yields on high-quality corporate debt and use of our third-party actuary’s discount rate model. This model
calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from bond
yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are
rated AA or higher by a recognized rating agency, only non-callable bonds are included and outlier bonds (bonds that have a
yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is
required to have at least $300 million par value outstanding. The constructed yield curve is based on those bonds representing
the 50% highest yielding issuances within each defined maturity group.
The asset rate of return assumption for the funded U.S. plan considers the plan’s asset mix (currently targeted at
approximately 55% equity and 45% other fixed income securities), past performance and other factors. Certain components of
the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields.
Compensation change assumptions are based on historical experience, anticipated future management actions and
demographics of the benefit plans. Health care cost trend assumptions are developed based on historical cost data, the near-term
outlook and an assessment of likely long-term trends.
Item 8. Financial Statements and Supplementary Data – Note 20 to the consolidated financial statements includes detailed
information about the assumptions used to calculate the components of our annual defined benefit pension and other
postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the
consolidated balance sheets.
Contingent Liabilities
We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, as well as tax
disputes and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for
many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations
50
of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental
remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on
the extent and nature of site contamination and improvements in technology. Our in-house legal counsel regularly assesses
these contingent liabilities. In certain circumstances outside legal counsel is utilized.
We generally record losses related to these types of contingencies as other operating expense or general and administrative
expense in the consolidated statements of income, except for tax contingencies unrelated to income taxes, which are recorded as
taxes other than income (such as production, severance and ad valorem taxes). For additional information on contingent
liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical
because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of
reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
Accounting Standards Not Yet Adopted
See Item 8. Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements.
51
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks related to the volatility of crude oil and condensate, NGLs and natural gas prices as the
volatility of these prices continues to impact our industry. We expect commodity prices to remain volatile and unpredictable in
the future. We are also exposed to market risks related to changes in interest rates. We employ various strategies, including the
use of financial derivative instruments, to manage the risks related to these fluctuations. We are at risk for changes in the fair
value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the
underlying commodity or financial transaction. While the use of derivative instruments could materially affect our results of
operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse
effect on our financial position or liquidity.
See Item 8. Financial Statements and Supplementary Data – Note 16 and Note 17 to the consolidated financial statements
for more information about the fair value measurement of our derivatives, the amounts recorded in our consolidated balance
sheets and statements of income and the related notional amounts.
Commodity Price Risk
Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements
dictated by supply and demand. However, management will periodically protect prices on forecasted sales to support cash flow
and liquidity, as deemed appropriate. We may use a variety of commodity derivative instruments, including futures, forwards,
swaps and combinations of options, as part of an overall program to manage commodity price risk in our business. Our
consolidated results for 2020, 2019 and 2018 were impacted by crude oil and natural gas derivatives related to a portion of our
forecasted United States sales.
As of December 31, 2020, we had various open commodity derivatives. Based on the December 31, 2020 published
NYMEX WTI, natural gas and NGL futures prices, a hypothetical 10% change (per bbl for crude oil and NGL and per MMBtu
for natural gas) would change the fair values of our $23 million net liability position to the following:
(In millions)
Hypothetical Price Increase of 10% Hypothetical Price Decrease of 10%
Derivative asset (liability) – Crude Oil
Derivative asset (liability) – Natural Gas
Derivative liability – NGL
Total
Interest Rate Risk
$
$
(74) $
(10)
(10)
(94) $
10
25
(1)
34
At December 31, 2020 our portfolio of current and long-term debt is comprised of fixed-rate instruments with an
outstanding balance of $5.4 billion. Our sensitivity to interest rate movements and corresponding changes in the fair value of
our fixed-rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise
retire fixed-rate debt at prices different than carrying value.
At December 31, 2020, we had forward starting interest rate swap agreements with a total notional amount of $670 million
designated as cash flow hedges and $500 million not designated as hedges. We utilize cash flow hedges to manage our
exposure to interest rate movements by utilizing interest rate swap agreements to hedge variations in cash flows related to (1)
the 1-month LIBOR component of future lease payments on our future Houston office and (2) the benchmark LIBOR index for
our debt due in 2025. We de-designated the cash flow hedges related to our debt due in 2022 during the third quarter of 2020. A
hypothetical 10% change in interest rates would change the fair values of our $3 million net asset position of our cash flow
hedge and our $10 million net asset position of our de-designated cash flow hedge to the following as of December 31, 2020:
(In millions)
Interest rate asset (liability) – designated as cash flow hedges
Interest rate asset – not designated as cash flow hedges
Total
Hypothetical Interest
Rate Increase of 10%
Hypothetical Interest
Rate Decrease of 10%
$
$
8
$
16
24
$
(3)
5
2
52
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices fall below
certain levels, some of our counterparties may experience liquidity problems and may not be able to meet their financial
obligations to us. We review the creditworthiness of counterparties and use master netting agreements when appropriate.
53
Item 8. Financial Statements and Supplementary Data
Index
Management’s Responsibilities for Financial Statements
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm Audited
Consolidated Financial Statements
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Select Quarterly Financial Data (Unaudited)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Page
55
55
56
59
60
61
62
63
64
103
104
54
Management’s Responsibilities for Financial Statements
To the Stockholders of Marathon Oil Corporation:
The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries
(“Marathon Oil”) are the responsibility of management and have been prepared in conformity with accounting principles
generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates.
The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated
financial statements.
Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by
organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at
assuring that its policies and methods are understood throughout the organization.
The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial
reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly
meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to
monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated
financial statements.
/s/ Lee M. Tillman
Chairman, President and Chief Executive Officer
/s/ Dane E. Whitehead
Executive Vice President and Chief Financial
Officer
Management’s Report on Internal Control over Financial Reporting
To the Stockholders of Marathon Oil Corporation:
Marathon Oil’s management is responsible for establishing and maintaining adequate internal control over financial
reporting (as defined in Rules 13(a) – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the
consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and
even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may
deteriorate.
An evaluation of the design and effectiveness of our internal control over financial reporting, based on the 2013 framework
in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission, was conducted under the supervision and with the participation of management, including our Chief Executive
Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon Oil’s management concluded that its
internal control over financial reporting was effective as of December 31, 2020.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2020 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included
herein.
/s/ Lee M. Tillman
Chairman, President and Chief Executive Officer
/s/ Dane E. Whitehead
Executive Vice President and Chief Financial
Officer
55
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Marathon Oil Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Marathon Oil Corporation and its subsidiaries (the
“Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income,
of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2020, including the
related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal
control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013)
issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal
control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included
in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express
opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting
based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
56
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or
disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate..
The Impact of Proved Oil and Condensate, Natural Gas Liquids (NGLs) and Natural Gas Reserves on Proved Oil and Gas
Properties, Net
As described in Notes 1 and 11 to the consolidated financial statements, the Company’s consolidated property, plant and
equipment, net balance was $15,638 million as of December 31, 2020, and depreciation, depletion, and amortization (DD&A)
expense for the year ended December 31, 2020 was $2,316 million. The Company follows the successful efforts method of
accounting for its oil and gas producing activities. Under this method, capitalized costs to acquire oil and natural gas properties
are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory
wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed
reserves. As disclosed by management, reserve estimates may change as additional information becomes available and as
contractual, operational, economic and political conditions change. The data for a given reservoir may also change over time as
a result of numerous factors including, but not limited to, additional development activity and future development costs,
production history and continual reassessment of the viability of future production volumes under varying economic conditions.
The estimates of oil and condensate, NGLs and natural gas reserves have been developed by specialists, specifically petroleum
engineers and geoscientists.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and
condensate, NGLs and natural gas reserves on proved oil and natural gas properties, net is a critical audit matter are (i) the
significant judgment by management, including the use of specialists, when developing the estimates of proved oil and
condensate, NGLs and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort
in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and
its specialists in developing the estimates of proved oil and condensate, NGLs, and natural gas reserves volumes.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to
management’s estimates of proved oil and condensate, NGLs, and natural gas reserves. The work of management’s specialists
was used in performing the procedures to evaluate the reasonableness of the proved oil and condensate, NGLs, and natural gas
reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship
with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by
the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.
Impairment Assessment of the EG Holdings Equity Method Investment
As described in Notes 1 and 12 to the consolidated financial statements, the Company recorded impairments of $171 million to
its investment in an equity method investee, which was reflected in income (loss) from equity method investments for the year
ended December 31, 2020. Management assesses equity method investments for impairment whenever changes in the facts and
circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred and is other than temporary,
the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included
in income. Management estimated the fair value of the Company’s equity method investment using an income approach,
specifically utilizing a discounted cash flow analysis. The estimated fair value was based on significant inputs not observable in
the market, such as the amount of gas processed by the plant, future commodity prices, forecasted operating expenses, discount
rate and estimated cash returned to shareholders.
The principal considerations for our determination that performing procedures relating to the impairment assessment of the EG
Holdings equity method investment is a critical audit matter are (i) the significant judgment by management, including the use
of specialists, when developing the fair value measurement of the equity method investment and (ii) a high degree of auditor
judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to the
future gas volumes to be processed by the plant.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to
management’s impairment assessment of the EG Holdings equity method investment. These procedures also included, among
57
others (i) testing management’s process for developing the fair value estimate; (ii) evaluating the appropriateness of the
discounted cash flow analysis; (iii) testing the completeness and accuracy of underlying data used in the analysis; and (iv)
evaluating the reasonableness of significant assumption used by management related to the future gas volumes to be processed
by the plant. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the
natural gas reserve volumes as stated in the Critical Audit Matter titled “Impact of Proved Oil and Condensate, Natural Gas
Liquids (NGLs), and Natural Gas Reserves on Proved Oil and Gas Properties, Net” and the reasonableness of the future gas
volumes to be processed by the plant. As a basis for using this work, the specialists’ qualifications were understood and the
Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the analysis
and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 23, 2021
We have served as the Company’s auditor since 1982.
58
MARATHON OIL CORPORATION
Consolidated Statements of Income
(In millions, except per share data)
Revenues and other income:
Revenues from contracts with customers
Net gain (loss) on commodity derivatives
Income (loss) from equity method investments
Net gain on disposal of assets
Other income
Total revenues and other income
Costs and expenses:
Production
Shipping, handling and other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Total costs and expenses
Income (loss) from operations
Net interest and other
Other net periodic benefit (costs) credits
Loss on early extinguishment of debt
Income (loss) before income taxes
Provision (benefit) for income taxes
Net income (loss)
Net income (loss) per share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
Year Ended December 31,
2020
2019
2018
$
3,097 $
5,063 $
5,902
116
(161)
9
25
3,086
555
596
181
2,316
144
200
274
4,266
(1,180)
(256)
(1)
(28)
(1,465)
(14)
(1,451) $
(1.83) $
(1.83) $
792
792
(72)
87
50
62
(14)
225
319
150
5,190
6,582
712
605
149
2,397
24
311
356
4,554
636
(244)
3
(3)
392
(88)
480 $
0.59 $
0.59 $
810
810
842
575
289
2,441
75
299
394
4,915
1,667
(226)
(14)
—
1,427
331
1,096
1.30
1.29
846
847
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
59
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income
(In millions)
Net income (loss)
Other comprehensive income (loss), net of tax
Change in actuarial gain (loss) and other for postretirement and
postemployment plans
Change in derivative hedges unrecognized gain (loss)
Foreign currency translation adjustment related to sale of U.K.
business
Other
Other comprehensive income (loss)
Comprehensive income (loss)
Year Ended December 31,
2020
2019
2018
$
(1,451) $
480 $
1,096
(30)
(2)
—
—
(32)
16
2
23
1
42
$
(1,483) $
522 $
121
—
—
4
125
1,221
The accompanying notes are an integral part of these consolidated financial statements.
60
MARATHON OIL CORPORATION
Consolidated Balance Sheet
(In millions, except par values and share amounts)
Assets
Current assets:
Cash and cash equivalents
Receivables, less reserve of $22 and $11
Inventories
Other current assets
Total current assets
Equity method investments
Property, plant and equipment, less accumulated depreciation, depletion and amortization of
$20,358 and $18,003
Goodwill
Other noncurrent assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Payroll and benefits payable
Accrued taxes
Other current liabilities
Total current liabilities
Long-term debt
Deferred tax liabilities
Defined benefit postretirement plan obligations
Asset retirement obligations
Deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)
Common stock:
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at
December 31, 2020 and December 31, 2019)
Held in treasury, at cost – 148 million shares and 141 million shares
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
Total liabilities and stockholders’ equity
The accompanying notes are an integral part of these consolidated financial statements.
61
December 31,
2020
2019
$
742 $
747
76
47
1,612
447
858
1,122
72
83
2,135
663
15,638
17,000
—
259
95
352
$
17,956 $
20,245
$
837 $
1,307
57
72
247
1,213
5,404
163
180
241
194
112
118
208
1,745
5,501
186
183
243
234
7,395
8,092
—
—
937
(4,089)
7,174
6,466
73
10,561
$
17,956 $
937
(4,089)
7,207
7,993
105
12,153
20,245
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
Year Ended December 31,
2019
2018
2020
$
(1,451) $
480 $
1,096
2,316
144
159
(9)
28
(22)
(116)
143
(43)
57
210
367
(4)
(381)
75
—
1,473
(1,343)
15
(1)
18
7
1
(1,303)
2,397
24
114
(50)
3
(34)
72
52
(52)
60
18
52
3
(187)
(4)
(199)
2,749
(2,550)
36
(293)
(76)
64
1
(2,818)
400
(500)
(27)
(92)
(64)
(3)
(286)
—
(116)
858
—
742 $
600
(600)
(2)
(362)
(162)
(9)
(535)
—
(604)
1,462
—
858 $
2,441
75
255
(319)
—
52
14
(281)
(65)
53
45
(133)
(1)
179
(22)
(155)
3,234
(2,753)
(26)
(25)
1,264
57
13
(1,470)
—
—
—
(713)
(169)
23
(859)
(2)
903
563
(4)
1,462
(In millions)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation, depletion and amortization
Impairments
Exploratory dry well costs and unproved property impairments
Net gain on disposal of assets
Loss on early extinguishment of debt
Deferred income taxes
Net (gain) loss on derivative instruments
Net settlements of derivative instruments
Pension and other post retirement benefits, net
Stock-based compensation
Equity method investments, net
Changes in:
Current receivables
Inventories
Current accounts payable and accrued liabilities
Other current assets and liabilities
All other operating, net
Net cash provided by operating activities
Investing activities:
Additions to property, plant and equipment
Additions to other assets
Acquisitions, net of cash acquired
Disposal of assets, net of cash transferred to the buyer
Equity method investments - return of capital
All other investing, net
Net cash used in investing activities
Financing activities:
Borrowings
Debt repayments
Debt extinguishment costs
Purchases of common stock
Dividends paid
All other financing, net
Net cash used in financing activities
Effect of exchange rate on cash and cash equivalents
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents included in current assets held for sale
Cash and cash equivalents at end of period
The accompanying notes are an integral part of these consolidated financial statements.
$
62
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity
Total Equity of Marathon Oil Stockholders
(In millions)
Preferred
Stock
Common
Stock
Treasury
Stock
Additional
Paid-in
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
December 31, 2017 Balance
$
— $
937 $
(3,325) $
7,379 $
6,779 $
(62) $
11,708
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net income
Other comprehensive income
Dividends paid ($0.20 per share)
—
—
—
—
—
—
—
—
—
—
—
—
221
(712)
—
—
—
—
(109)
—
(32)
—
—
—
—
—
—
1,096
—
(169)
—
—
—
—
125
—
112
(712)
(32)
1,096
125
(169)
December 31, 2018 Balance
$
— $
937 $
(3,816) $
7,238 $
7,706 $
63 $
12,128
Cumulative-effect adjustment
(Note 2)
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net income
Other comprehensive income
Dividends paid ($0.20 per share)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
89
(362)
—
—
—
—
—
(26)
—
(5)
—
—
—
(31)
—
—
—
480
—
(162)
—
—
—
—
—
42
—
(31)
63
(362)
(5)
480
42
(162)
December 31, 2019 Balance
$
— $
937 $
(4,089) $
7,207 $
7,993 $
105 $
12,153
Cumulative-effect adjustment
(Note 2)
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net loss
Other comprehensive loss
Dividends paid ($0.08 per share)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
91
(91)
—
—
—
—
—
(60)
—
27
—
—
—
(12)
—
—
—
(1,451)
—
(64)
—
—
—
—
—
(32)
—
(12)
31
(91)
27
(1,451)
(32)
(64)
December 31, 2020 Balance
$
— $
937 $
(4,089) $
7,174 $
6,466 $
73 $
10,561
(Shares in millions)
December 31, 2017 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2018 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2019 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2020 Balance
Preferred
Stock
Common
Stock
Treasury
Stock
—
—
—
—
—
—
—
—
—
—
937
—
—
937
—
—
937
—
—
937
87
(6)
37
118
(2)
25
141
(3)
10
148
The accompanying notes are an integral part of these consolidated financial statements.
63
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
1. Summary of Principal Accounting Policies
We are an independent exploration and production company engaged in exploration, production and marketing of crude oil
and condensate, NGLs and natural gas; as well as production and marketing of products manufactured from natural gas, such as
LNG and methanol, in E.G.
Basis of presentation and principles applied in consolidation – These consolidated financial statements, including notes,
have been prepared in accordance with U.S. GAAP. These consolidated financial statements include the accounts of our
controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are
consolidated on a pro rata basis.
Equity method investments – Investments in entities over which we have significant influence, but not control, are
accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the
minority stockholders have substantive participating rights in the investee. Income from equity method investments represents
our proportionate share of net income generated by the equity method investees and is reflected in revenues and other income in
our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated
balance sheet.
Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in
value may have occurred. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity
method investment is written down to fair value, and the amount of the write-down is included in income.
Use of estimates – The preparation of financial statements in accordance with U.S. GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the
respective reporting periods.
Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires
judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties
inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any
reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As
a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are
ultimately recovered. See unaudited Supplementary Data – Supplementary Information on Oil and Gas Producing
Activities for further detail.
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset
retirement obligations, goodwill, valuation of derivative instruments and valuation allowances for deferred income tax assets,
among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign
currency transaction gains and losses are included in net income.
Revenue recognition – Revenues associated with the sales of crude oil and condensate, NGLs and natural gas are
recognized when our performance obligation is satisfied, which typically occurs at the point where control transfers to the
customer based on contract terms. Revenue is measured as the amount the company expects to receive in exchange for
transferring commodities to the customer. Our hydrocarbon sales are typically based on prevailing market-based prices and may
include quality or location differential adjustments. Payment is generally due within 30 days of delivery.
We typically incur shipping and handling costs prior to control transferring to the customer and account for these activities
as fulfillment costs. These costs are reflected in shipping, handling and other operating expense in our consolidated statement of
income.
Our U.S. production of crude oil and condensate, NGLs and natural gas is generally sold immediately and transported to
market. In our international segment, liquid hydrocarbon production may be stored as inventory and sold at a later time.
Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly
liquid debt instruments with original maturities of three months or less.
Accounts receivable – The majority of our receivables are from purchasers of commodities or joint interest owners in
properties we operate, both of which are recorded at estimated or invoiced amounts and do not bear interest. We often have the
64
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit
reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing
customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. We routinely assess the
collectability of receivable balances to determine if the amount of the reserve in allowance for doubtful accounts is sufficient.
Inventories – Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net
realizable value. Supplies and other items consist principally of tubular goods and equipment, which are valued at weighted
average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a
particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified
location on the same or another specified date from the same counterparty. We account for such matching buy/sell
arrangements as exchanges of inventory.
Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk,
commodity locational risk and interest rate risk. All derivative instruments are recorded at fair value. Commodity derivatives
and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by
master netting agreements. Cash flows related to derivatives used to manage commodity price risk, and interest rate risk are
classified in operating activities. Our derivative instruments contain no significant contingent credit features.
Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed
interest rate debt in our portfolio. Changes in the fair values of both the hedged item and the related derivative are recognized
immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net
income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
Cash flow hedges – We may use interest rate derivative instruments to manage the risk of interest rate changes during the
period prior to anticipated borrowings as well as to stabilize future lease payments on our future Houston office, and designate
them as cash flow hedges. Derivative instruments designated as cash flow hedges are linked to specific assets and liabilities or
to specific firm commitments or forecasted transactions. The changes in the fair value of a qualifying cash flow hedge are
recorded in other comprehensive income until the hedged transaction affects earnings and are then reclassified into net income.
Beginning in 2019, ineffective portions of a cash flow hedge are no longer measured or disclosed separately. However, if it is
determined that the likelihood of the original forecasted transaction occurring is no longer probable or the cash flow hedge is no
longer expected to be highly effective, subsequent changes in fair value of the derivatives instrument are recorded in net
income.
Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives
used primarily to manage price and locational risks on the forecasted sale of crude oil, NGLs and natural gas that we produce.
Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and
market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to
our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage
counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their
financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting
period.
Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities.
Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells in
progress and those that find proved reserves and to drill development wells are capitalized. Costs to drill exploratory wells that
do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are
expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the
well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient
progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory
well costs is monitored continuously and reviewed at least quarterly.
65
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties are depreciated and
depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and
development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves.
Support equipment and other property, plant and equipment related to oil and gas producing activities, as well as property, plant
and equipment unrelated to oil and gas producing activities, are recorded at cost and depreciated on a straight-line basis over the
estimated useful lives of the assets. The table below summarizes these assets by type, useful life and the gross asset balance as
of the periods presented.
Type of Asset
Range of Useful Lives
2020
2019
December 31,
Office furniture, equipment and computer hardware
Pipelines
Plants, facilities and infrastructure
4 to 15 years
5 to 40 years
3 to 40 years
$
$
$
(in millions)
682 $
12 $
1,646 $
670
12
1,624
Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and
development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its
eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the
asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical
grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency
amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value,
as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved
property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir
performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments
are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income.
Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any
gains or losses are reflected in net gain (loss) on disposal of assets in our consolidated statements of income. Gains on the
disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on
disposal is expected, such losses are recognized either when the assets are classified as held for sale, or are measured using a
probability weighted income approach based on both the anticipated sales price and a held-for-use model depending on timing
of the sale. Proceeds from the disposal of a portion of property, plant and equipment depreciated on a group basis are credited to
accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to
zero.
Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in
the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or
changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value.
The impairment test requires allocating goodwill and other assets and liabilities to a reporting unit. The fair value of a reporting
unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the
book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.
Environmental costs – We provide for remediation costs and penalties when the responsibility to remediate is probable and
the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a
feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known
environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable.
Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the
environmental safety or efficiency of the existing assets.
Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the
obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to
the abandonment of oil and gas producing facilities. Asset retirement obligations for such facilities include costs to dismantle
and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land,
including those leased. Estimates of these costs are developed for each property based on the type of production facilities and
equipment, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and
consultations with construction and engineering professionals.
66
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time.
Depreciation is generally determined on a units-of-production basis based on estimated proved developed reserves for oil and
gas production facilities, while accretion of the liability occurs over the useful lives of the assets.
Deferred income taxes – Deferred tax assets and liabilities, measured at enacted tax rates, are recognized for the estimated
future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and
their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our
deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than
not that some portion or all of the deferred tax assets will not be realized. These factors include whether we are in a cumulative
loss position in recent years, our reversal of temporary differences, and our expectation to generate sufficient future taxable
income. We use the liability method in determining our provision and liabilities for our income taxes, under which current and
deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.
Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the
Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the
time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of
the stock option award. Of the required assumptions, the expected volatility of our stock price and the stock price in relation to
the strike price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed
current information which reasonably support these assumptions.
The fair value of our restricted stock awards, restricted stock units and Director restricted stock units is determined based
on the market value of our common stock on the date of grant. Restricted stock awards, restricted stock units and Director
restricted stock units are removed from Treasury Stock at grant, vesting and distribution, respectively.
The fair value of our cash-settled stock-based performance units is estimated using the Monte Carlo simulation method.
Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-
measured quarterly until settlement. The fair value of our stock-settled stock-based performance units is estimated using the
Monte Carlo simulation method at grant date only. Since these awards are settled in stock, they are classified as equity.
Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected
to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture
results are different than expected, adjustments to recognized compensation expense may be required in future periods.
2. Accounting Standards
Recently Adopted
Financial instruments – credit losses
In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade
receivables, net investments in leases, debt securities, loans and certain other instruments. On January 1, 2020 we adopted this
standard using the modified retrospective transition method through a cumulative-effect adjustment of $12 million to retained
earnings as of the beginning of the adoption period. The standard requires the use of a forward-looking “expected loss” model
as opposed to the “incurred loss” model used previously. See Note 9 for more information on credit losses.
67
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
3. Income (loss) and Dividends per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income
(loss) per share assumes exercise of stock options in all periods, provided the effect is not antidilutive. The per share
calculations below exclude 7 million, 6 million and 6 million stock options in 2020, 2019 and 2018 that were antidilutive.
(In millions, except per share data)
Net income (loss)
Weighted average common shares outstanding
Effect of dilutive securities
Weighted average common shares, diluted
Net income (loss) per share:
Basic
Diluted
Dividends per share
4. Acquisitions
United States Segment
Year Ended December 31,
2020
2019
2018
$
(1,451) $
480 $
1,096
792
—
792
(1.83) $
(1.83) $
0.08 $
810
—
810
0.59 $
0.59 $
0.20 $
846
1
847
1.30
1.29
0.20
$
$
$
In the fourth quarter of 2019, we acquired approximately 40,000 net acres in a Texas Delaware oil play in West Texas from
multiple sellers for $106 million. We accounted for these transactions as an asset acquisition, allocating the purchase price to
unproved property within property, plant and equipment.
During the fourth quarter of 2019, we acquired a 100% working interest in approximately 18,000 net acres in the Eagle
Ford from Rocky Creek Resources, LLC and RCR Midstream, LLC for $191 million in cash, subject to post-closing
adjustments. We accounted for this transaction as a business combination, with the entire purchase price allocated between
proved property, unproved property and other assets, all within property, plant and equipment.
The fair values of the assets acquired were measured using the market approach, specifically the market comparable
technique. The fair values were based on market-corroborated inputs, which were derived from observable market data; such
inputs represent Level 2 inputs. As the acquisition date was December 31, 2019, there is not a pro forma effect of this
transaction on our consolidated statement of income.
5. Dispositions
United States Segment
In the third quarter of 2018, we closed on the sale of non-core, non-operated conventional properties, primarily in the Gulf
of Mexico, for combined net proceeds of $16 million, before closing adjustments. A pre-tax gain of $32 million was recognized
in the third quarter of 2018.
International Segment
On July 1, 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and Marathon Oil West of Shetlands
Limited) for proceeds of $95 million which reflects the assumption by RockRose Energy PLC (“RockRose”) of the U.K.
business’ cash equivalent balance and working capital balance as of year-end 2018. During the third quarter of 2019, we
recorded a $6 million liability and corresponding expense related to the estimated fair value of our exposure to surety bonds we
continued to hold that guaranteed decommissioning liabilities of Marathon Oil U.K. LLC. In November 2019, RockRose posted
replacement security and accordingly, we reversed the aforementioned $6 million (see Note 26 for further detail). Income
before taxes relating to our U.K. business for the year ended December 31, 2019 and 2018, was $33 million and $261 million,
respectively. See Note 13 and Note 20 for additional details on U.K. ARO and the defined benefit pension plan as it relates to
this disposition.
In the second quarter of 2019, we closed on the sale of our 15% non-operated interest in the Atrush block in Kurdistan for
proceeds of $63 million, before closing adjustments.
68
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
In the first quarter of 2018, we closed on the sale of our subsidiary, Marathon Oil Libya Limited, which held our 16.33%
non-operated interest in the Waha concessions in Libya, to a subsidiary of Total S.A. (Elf Aquitaine SAS) for proceeds of
approximately $450 million, excluding closing adjustments, and recognized a pre-tax gain of $255 million.
6. Revenues
The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and
term agreements with our customers in the United States and various international locations.
As of December 31, 2020 and December 31, 2019, receivables from contracts with customers, included in receivables, less
reserves were $572 million and $837 million, respectively.
The following tables present our revenues from contracts with customers disaggregated by product type and geographic
areas.
United States
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
$
Revenues from contracts with customers $
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
$
Revenues from contracts with customers $
Year Ended December 31, 2020
Eagle
Ford
Bakken
Oklahoma
Northern
Delaware Other U.S.
Total
830 $
74
86
6
996 $
984 $
54
34
—
1,072 $
235 $
89
127
—
451 $
204 $
20
18
—
242 $
69 $
6
10
78
163 $
2,322
243
275
84
2,924
Year Ended December 31, 2019
Eagle
Ford
Bakken
Oklahoma
Northern
Delaware Other U.S.
Total
1,358 $
114
121
7
1,600 $
1,686 $
46
39
—
1,771 $
425 $
116
156
—
697 $
316 $
26
16
—
358 $
102 $
5
17
52
176 $
3,887
307
349
59
4,602
69
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
Year Ended December 31, 2018
Eagle
Ford
Bakken
Oklahoma
Northern
Delaware Other U.S.
Total
$
1,554 $
1,568 $
426 $
235 $
164 $
3,947
205
145
8
62
38
—
181
184
—
38
20
—
9
26
23
495
413
31
Revenues from contracts with customers $
1,912 $
1,668 $
791 $
293 $
222 $
4,886
International
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
Revenues from contracts with customers
$
$
Year Ended December 31, 2020
E.G.
Year Ended December 31, 2019
E.G.
U.K.
Other
International
Total
$
271 $
107 $
20 $
4
32
—
307 $
1
12
14
134 $
—
—
—
20 $
140
4
29
—
173
398
5
44
14
461
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
Revenues from contracts with customers
$
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
$
Revenues from contracts with customers $
Year Ended December 31, 2018
E.G.
U.K.
Libya
Other
International
Total
342 $
4
37
1
384 $
282 $
5
40
32
359 $
187 $
—
9
—
196 $
77 $
—
—
—
77 $
888
9
86
33
1,016
In 2020, sales to Marathon Petroleum Corporation and Koch Resources LLC and each of their respective affiliates,
accounted for approximately 13% and 12%, respectively, of our total revenues. In 2019, sales to Marathon Petroleum
Corporation, Koch Resources LLC, Valero Marketing and Supply and Shell Trading and their respective affiliates, accounted
for approximately 13%, 13%, 11% and 10%, respectively, 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.
The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are
adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is
highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall.
Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we
do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as
product specifications are standardized for the industry and are typically measured when transferred to a common carrier or
midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those
specifications.
70
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in
excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.
Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes.
We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a
customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of
hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under
these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production
from the dedicated wells or specified contractual volumes of hydrocarbons.
We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to
explore, develop and produce oil and gas properties in accordance with the joint operating arrangements. Other working interest
owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part
of customer relationships and such reimbursements will continue to not be recorded as revenues within the scope of the revenue
accounting standard.
In addition, we commonly market the share of production belonging to other working interest owners as the operator of
jointly owned oil and gas properties. We concluded that those marketing activities are carried out as part of the collaborative
arrangement. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for
the volumes associated with our net production.
Crude oil and condensate
For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control
of the crude at the designated delivery points, which include pipelines, trucks or vessels.
Natural gas and NGLs
When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural
gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements.
In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant
when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in
time where control is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the
natural gas and NGLs.
The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost,
since we make those payments in exchange for distinct services. Under some of our natural gas processing agreements, we have
an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those
circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the
designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the
customer.
We have “percentage-of-proceeds” arrangements with some midstream entities where they retain a percentage of the
proceeds collected for selling our processed natural gas and NGLs as compensation for their processing and marketing services.
We recognize revenue for the gross sales volumes and recognize the proceeds retained by midstream companies as shipping and
handling cost.
7. Segment Information
We have two reportable operating segments. Both of these segments are organized and managed based upon geographic
location and the nature of the products and services offered.
•
•
United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the
United States
International (“Int’l”) – 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.
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
71
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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.
(In millions)
Revenues from contracts with customers
Net gain (loss) on commodity derivatives
Income (loss) from equity method investments
Net gain on disposal of assets
Other income
Less costs and expenses:
Production
Shipping, handling and other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Other net periodic benefit costs
Loss on early extinguishment of debt
Income tax benefit
Segment income (loss)
Total assets
Capital expenditures(a)
Year Ended December 31, 2020
U.S.
Int’l
Not Allocated
to Segments
$
2,924 $
173 $
143
—
—
15
494
534
97
2,211
—
193
115
—
—
—
10
—
7
59
8
—
82
—
—
14
—
—
—
(9)
—
(3)
—
(27) (b)
(171) (c)
9
3
2
54
84 (d)
23
(e)
(f)
144
7
145
256
1 (g)
28
(2)
Total
$
3,097
116
(161)
9
25
555
596
181
2,316
144
200
274
256
1
28
(14)
$
$
$
(553) $
16,063 $
1,137 $
30 $
1,081 $
1 $
(928)
812
13
(1,451)
$
$ 17,956
1,151
$
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Includes accruals and excludes acquisitions.
Unrealized loss on commodity derivative instruments (See Note 16).
Partial impairment of investment in equity method investee (See Note 24).
Primarily related to unproved property impairments of non-core acreage in our United States segment.
Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 15) and proved property impairments of $49 million
related to a damaged well in our United States segment.
Includes severance expenses associated with workforce reductions of $17 million.
Includes pension settlement loss of $30 million and pension curtailment gain of $17 million (See Note 20).
72
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
Revenues from contracts with customers
Net gain (loss) on commodity derivatives
Income from equity method investments
Net gain on disposal of assets
Other income
Less costs and expenses:
Production
Shipping, handling and other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Other net periodic benefit credit
Loss on early extinguishment of debt
Income tax provision (benefit)
Segment income (loss)
Total assets
Capital expenditures(a)
Year Ended December 31, 2019
U.S.
Int’l
Not Allocated
to Segments
$
4,602 $
461 $
52
—
—
13
588
561
149
2,250
—
311
127
—
—
—
—
87
—
9
126
26
—
121
—
—
25
—
(3)
—
6
675 $
29
233 $
17,781 $
2,550 $
1,530 $
16 $
$
$
$
—
(124) (b)
—
50 (c)
40
(2)
18
—
26
24 (d)
—
204
244
— (e)
3
(123)
(428)
934
25
Total
$
5,063
(72)
87
50
62
712
605
149
2,397
24
311
356
244
(3)
3
(88)
480
$
$ 20,245
2,591
$
(a)
(b)
(c)
(d)
(e)
Includes accruals and excludes acquisitions.
Unrealized loss on commodity derivative instruments (See Note 16).
Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) and the sale of our U.K. business (See Note 5).
Primarily a result of anticipated sales of non-core proved properties in our International and United States segments (See Note 12).
Includes pension settlement loss of $12 million (See Note 20).
73
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
Revenues from contracts with customers
Net gain (loss) on commodity derivatives
Income from equity method investments
Net gain on disposal of assets
Other income
Less costs and expenses:
Production
Shipping, handling and other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Other net periodic benefit (costs) credits
Income tax provision (benefit)
Segment income
Total assets
Capital expenditures(a)
Year Ended December 31, 2018
U.S.
Int’l
Not Allocated
to Segments
$
4,886 $
1,016 $
(281)
—
—
16
625
499
246
2,217
—
301
146
—
—
(21)
—
225
—
12
215
70
3
197
—
—
32
—
(9)
272
—
267 (b)
—
319 (c)
122 (d)
2
6
40 (e)
27
75 (f)
(2)
216
226
23 (g)
80
Total
$
5,902
(14)
225
319
150
842
575
289
2,441
75
299
394
226
14
331
$
$
$
608 $
17,321 $
473 $
2,083 $
15
1,917
$
1,096
$ 21,321
2,620 $
39 $
26
$
2,685
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Includes accruals and excludes acquisitions.
Unrealized gain on commodity derivative instruments (See Note 16).
Primarily related to the gain on sale of our Libya subsidiary (See Note 5).
Primarily a reduction of asset retirement obligations in our International segment (See Note 13).
Primarily related to dry well expense and unproved property impairments associated with the Rodo well in Alba Block Sub Area B, offshore E.G. (See
Note 12).
Due to the anticipated sales of certain non-core proved properties in our International and United States segments (See Note 12).
Includes pension settlement loss of $21 million (See Note 20).
The following summarizes property, plant and equipment and equity method investments.
(In millions)
United States
Equatorial Guinea
Total long-lived assets
8. Income Taxes
Income (loss) before income taxes were:
(In millions)
United States
Foreign
Total
December 31,
2020
2019
$
$
15,224 $
861
16,085 $
16,507
1,156
17,663
Year Ended December 31,
2020
2019
2018
$
$
(1,319) $
(146)
(1,465) $
43 $
349
392 $
642
785
1,427
74
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Income tax provisions (benefits) were:
(In millions)
Federal
State and local
Foreign
Total
2020
Year Ended December 31,
2019
2018
Current Deferred
Total
Current Deferred
Total
Current Deferred
Total
$
(5) $
(2)
15
— $
(5) $
(116) $
(3) $
(119) $
(8)
(14)
(10)
1
4
58
3
(34)
7
24
6 $
(1)
— $
6
(23)
(24)
274
75
$
8 $
(22) $
(14) $
(54) $
(34) $
(88) $
279 $
52 $
349
331
A reconciliation of the federal statutory income tax rate applied to income (loss) before income taxes to the provision
(benefit) for income taxes follows:
(In millions)
Total pre-tax income (loss)
Total income tax expense (benefit)
Effective income tax rate
Income taxes at the statutory tax rate(a)
Effects of foreign operations
Adjustments to valuation allowances
State income taxes, net of federal benefit
Other federal tax effects
Income tax expense (benefit)
(a)
Year Ended December 31,
2020
(1,465)
(14)
1 %
(308)
23
239
6
26
(14)
2019
392
(88)
(22) %
83
(29)
(28)
11
(125)
(88)
2018
1,427
331
23 %
300
214
(177)
(17)
11
331
$
$
$
$
$
$
$
$
$
$
$
$
Includes income tax benefits primarily related to our U.S. federal income taxes where we have maintained a full valuation allowance since December
2016.
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of
income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the
amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.
Effects of foreign operations – The effects of foreign operations increased our tax expense in 2020 largely due to book
losses in foreign jurisdictions with no corresponding tax benefits. The effects of foreign operations decreased our tax expense in
2019 due to tax benefits related to our U.K. operations and pre-tax income in jurisdictions with effective tax rates lower than
the U.S. The effects of foreign operations increased our tax expense in 2018 due to the mix of pre-tax income between high and
low tax jurisdictions, including Libya where the tax rate was 93.5%. Excluding Libya, the effective tax rate would have been an
expense of 14% in 2018. As a result of the sale of our Libya subsidiary in the first quarter of 2018, we do not expect to incur
further tax expense related to Libya.
Adjustments to valuation allowances – Since December 31, 2016, we have maintained a full valuation allowance on our net
federal deferred tax assets. In all years, the most significant driver for the change in valuation allowance was due to current year
activity in the U.S.
Other federal tax effects – In 2020, the increase to other federal tax effects is largely related to non-deductible goodwill
impairment. The 2019 decrease in other federal tax effects is primarily related to the settlement of the 2010-2011 U.S. Federal
Tax Audit (“IRS Audit”) in the first quarter of 2019. The release of the accrued tax positions resulted in a $126 million tax
benefit, primarily related to AMT credits.
75
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Deferred tax assets and liabilities resulted from the following:
(In millions)
Deferred tax assets:
Employee benefits
Operating loss carryforwards
Capital loss carryforwards
Foreign tax credits
Other
Subtotal
Valuation allowance
Total deferred tax assets
Deferred tax liabilities:
Property, plant and equipment
Accrued revenue
Total deferred tax liabilities
Net deferred tax liabilities
Net deferred tax assets
Year Ended December 31,
2020
2019
$
77 $
1,966
—
611
43
2,697
(948)
1,749
1,892
20
1,912
163 $
— $
$
$
90
1,685
1
611
27
2,414
(699)
1,715
1,861
40
1,901
186
—
Operating loss carryforwards – At December 31, 2020, we have a gross deferred tax asset related to our operating loss
carryforwards of $2.0 billion, before valuation allowance. Deferred tax assets on U.S. operating loss carryforwards relating to
tax years beginning prior to January 1, 2018, include $655 million that expire in 2035 - 2037. Deferred tax assets on U.S.
operating loss carryforwards for tax years beginning after December 31, 2017, include $1.1 billion which can be carried
forward indefinitely. Deferred tax assets on foreign operating loss carryforwards include $14 million that begin to expire in
2021. Deferred tax assets on state operating loss carryforwards of $184 million expire in 2021 through 2039.
Foreign tax credits – At December 31, 2020, we reflect foreign tax credits of $611 million, which will expire in years 2022
through 2026.
Valuation allowances – At December 31, 2020, we reflect a valuation allowance in our consolidated balance sheet of $948
million against our net deferred tax assets in various jurisdictions in which we operate. The increase in valuation allowance
primarily relates to current year activity in the U.S.
Property, plant and equipment – At December 31, 2020, we reflected a deferred tax liability of $1.9 billion. The increase
primarily relates to current year activity in the U.S.
Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows:
(In millions)
Assets:
Other noncurrent assets
Liabilities:
Noncurrent deferred tax liabilities
Net deferred tax liabilities
Net deferred tax assets
December 31,
2020
2019
$
$
$
— $
163
163 $
— $
—
186
186
—
76
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
We are routinely undergoing examinations in the jurisdictions in which we operate. As of December 31, 2020, our income
tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:
United States(a)
Equatorial Guinea
(a)
Includes federal and state jurisdictions.
The following table summarizes the activity in unrecognized tax benefits:
2008 - 2019
2007 - 2019
(In millions)
Beginning balance
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Ending balance
2020
2019
2018
$
$
13 $
—
(5)
—
8 $
263 $
13
(152)
(111)
13 $
126
152
(15)
—
263
If the unrecognized tax benefits as of December 31, 2020 were recognized, $8 million would affect our effective income
tax rate. As of December 31, 2020, we do not expect uncertain tax positions to significantly change within the next twelve
months. During the first quarter of 2019, we withdrew our appeal related to the Brae area decommissioning costs in the U.K.,
thus the uncertain tax positions previously established are now considered effectively settled with no tax expense or benefit
impact. Also, in the first quarter of 2019, we settled the 2010-2011 IRS Audit, resulting in a tax benefit of $126 million.
Interest and penalties are recorded as part of the tax provision and were a $2 million tax benefit in 2020 and a $6 million
and $2 million tax expense in 2019 and 2018 related to unrecognized tax benefits. As of December 31, 2020, we had no
significant accrued interest or penalties related to income taxes. For December 31, 2019, $3 million of interest and penalties
were accrued related to income taxes.
In the third quarter of 2020, we received an $89 million cash refund related to alternative minimum tax credits and interest.
This refund was accelerated as a result of the enactment of the Coronavirus Aid, Relief, and Economic Security Act, commonly
referred to as the CARES Act, in the first quarter of 2020.
9. Credit Losses
The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, both
of which are recorded at estimated or invoiced amounts and do not bear interest. The majority of these receivables have
payment terms of 30 days or less. At the end of each reporting period, we assess the collectability of our receivables and
estimate the expected credit losses using historical data, current market conditions and reasonable and supportable forecasts of
future economic conditions.
We are exposed to credit losses through the receivables generated from sales of crude oil, NGLs and natural gas to our
customers. When dealing with the commodity purchasers, we conduct a credit review to assess each counterparty’s ability to
pay. The credit review considers our expected billing exposure, timing for payment and the counterparty’s established credit
rating with the rating agencies or our internal assessment of the counterparty’s creditworthiness based on our analysis of their
financial statements. Our evaluation also considers contract terms and other factors, such as country and/or political risk. A
credit limit is established for each counterparty based on the outcome of this review. We may require a bank letter of credit or a
prepayment to mitigate credit risk. We monitor our ongoing credit exposure through active review of counterparty balances
against contract terms and due dates. The expected credit losses related to receivables with the commodity purchasers were
determined using the weighted average probability of default method. We also collect revenues from our non-operated joint
properties where other oil and gas exploration and production companies operate the properties and market our share of
production and remit payments to us. The current expected credit losses related to these receivables were determined using the
loss rate method applied to aging pools.
We are exposed to credit losses from joint interest billings to other joint interest owners for properties we operate. For this
group of receivables, the expected credit losses are determined using the loss rate method applied to aging pools. Our
counterparties in this group include numerous large, mid-size and small oil and gas exploration and production companies.
Although we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest
billings or require a prepayment of future costs through cash calls, our credit loss exposure with this group is more significant
due to inherent ownership or billing adjustments. Also, some of our counterparties may experience liquidity problems and may
not be able to meet their financial obligations to us. Liquidity problems may increase in the future if hydrocarbon demand and/
77
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
or prices don’t materially increase from 2020 levels. Our current-period provision reflects the anticipated effects caused by the
market deterioration in 2020.
Changes in the allowance for doubtful accounts balance for the year were as follows:
(In millions)
Beginning balance as of January 1
Cumulative-effect adjustment
Current period provision(a)
Current period write offs
Recoveries of amounts previously reserved
Ending balance as of December 31
(a)
December 31, 2020
11
12
22
(13)
(10)
22
$
$
For the year ended December 31, 2020, the current period provision increased by $12 million in trade receivables and $10 million in joint interest
receivables.
10. Inventories
Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value.
Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and
reviewed periodically for obsolescence or impairment when market conditions indicate. The continued volatility and future
decline in crude oil and natural gas prices could affect the value of our inventories and result in future impairments.
(In millions)
Crude oil and natural gas
Supplies and other items
Inventories
11. Property, Plant and Equipment
(In millions)
United States
International
Not allocated to segments
Net property, plant and equipment
Changes in our capitalized exploratory well costs were as follows:
(In millions)
Beginning balance as of January 1
Additions
Charges to expense(a)
Transfers to development
Dispositions(b)
Ending balance as of December 31
(a)
(b)
2018 includes $32 million related to the Rodo well in Alba Block Sub Area B (See Note 12).
2018 includes the sale of our Libya subsidiary.
December 31,
2020
2019
10 $
66
76 $
10
62
72
December 31,
2020
2019
15,156 $
414
68
15,638 $
16,427
493
80
17,000
$
$
$
$
December 31,
2020
2019
2018
$
$
278 $
97
(1)
(164)
—
210 $
297 $
218
(5)
(230)
(2)
278 $
295
262
(35)
(197)
(28)
297
78
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
At December 31, 2020, we had $98 million of exploratory well costs capitalized greater than one year related to suspended
wells. Management believes these wells exhibit sufficient quantities of hydrocarbons to justify potential development. The vast
majority of the suspended wells require completion activities and installation of infrastructure in order to classify the reserves as
proved. At December 31, 2019 and 2018 we had $30 million and $6 million of exploratory well costs capitalized greater than
one year.
12. Impairments
During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of
hydrocarbons. The decreased demand, when coupled with an oversupplied market, caused a corresponding deterioration in
hydrocarbon prices. We reviewed our long-lived assets for indicators of impairment during the first quarter by conducting a
sensitivity analysis of the most impactful inputs to their undiscounted cash flows, including commodity prices, capital spend
and reductions in production volumes to correspond with lower capital spending. Our review concluded that the carrying
amounts of our long-lived assets are recoverable; however, further deterioration or a more sustained decline of commodity
prices may result in impairment charges in future periods.
We also reviewed our equity method investments for indicators of impairment. Equity method investments are assessed for
impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss in value
occurs that is deemed other than temporary, the carrying value of the equity method investment is written down to fair value.
During the second and third quarters of 2020, we recognized impairments related to one of our EG Holdings equity method
investments, as noted in the tables and further described below.
The following table summarizes impairment charges of proved properties, goodwill and equity method investments and
their corresponding fair values.
2020
2019
2018
(In millions)
Long-lived assets held for use
Goodwill
Equity method investment
Fair Value
Impairment
Fair Value
Impairment
Fair Value
Impairment
$
$
$
— $
— $
119 $
49 $
95
171
56 $
N/A $
N/A $
24 $
—
—
113 $
N/A $
N/A $
75
—
—
•
2020 – Impairments totaling $49 million of long-lived assets held for use resulted from a damaged, unsalvageable well
and related equipment in the Louisiana Austin Chalk. The related fair value was measured based on the salvage value
which resulted in a Level 3 classification.
We impaired the entire balance of our goodwill in the International reporting unit totaling $95 million of goodwill. See
Note 15 for further information.
Impairments also include charges recognized for our equity method investments of $171 million. During the second
and third quarters of 2020, the continuation of the depressed commodity prices, along with a reduction of our long-
term price forecasts of a gas index in which one of our equity method investees transacts, caused us to perform a
review of one of our equity method investments. Our review concluded that a loss of our investment value in one was
other than temporary and we recorded an impairment. Our remaining investments in equity method investees did not
experience losses in value that caused the fair values to be below their carrying values.
We estimated the fair value of our equity method investment using an income approach, specifically utilizing a
discounted cash flow analysis. The estimated fair value was based on significant inputs not observable in the market,
such as the amount of gas processed by the plant, future commodity prices, forecasted operating expenses, discount
rate and estimated cash returned to shareholders. Collectively, these inputs represent Level 3 measurements.
The impairments of our equity method investments were recognized in income (loss) from equity method investments
in our consolidated statements of income. The impairments caused us to incur a basis differential between the net book
value of our investment and the amount of our underlying share of equity in the investee’s net assets. The amount of
this basis differential was $140 million and is being accreted into income over the remaining useful life of the
investee’s primary assets.
Finally, we impaired $78 million of unproved property leases in Louisiana Austin Chalk in our United States segment
which was recognized in exploration expense in our consolidated statements of income. The impairment resulted from
a combination of factors including our geological assessment, seismic information, timing of lease expiration dates and
decisions not to develop acreage deemed non-core. Collectively, these inputs represent Level 3 measurements.
79
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
•
•
2019 – Impairments of $24 million, to an aggregate fair value of $56 million, were primarily a result of anticipated
sales for certain non-core proved properties in our United States segment and the sale of our non-operated interest in
the Atrush block (Kurdistan) in our International segment. The related fair value was measured using the market
approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification.
2018 – Impairments in our International and United States segments of $75 million, to a fair value of $113 million,
were largely the result of anticipated sales for certain non-core proved properties. The related fair value measurement
utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2
classification.
See Note 5 for discussion of the divestitures in further detail and Note 7 for relevant detail regarding segment presentation.
13. Asset Retirement Obligations
Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land at the end of oil and
gas production operations. Changes in asset retirement obligations for the periods ended December 31 were as follows:
(In millions)
Beginning balance as of January 1
Incurred liabilities, including acquisitions
Settled liabilities, including dispositions
Accretion expense (included in depreciation, depletion and amortization)
Revisions of estimates
Held for sale(a)
Ending balance as of December 31
(a)
2020
2019
254 $
6
(12)
12
(6)
—
254 $
1,145
34
(1,110)
31
46
108
254
$
$
In the first quarter of 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), including our $98 million asset retirement
obligation.
2020
•
Ending balance includes $13 million classified as short-term at December 31, 2020.
2019
•
•
Settled liabilities primarily relates to the sale of our U.K. business, which closed during the third quarter of 2019, and the
sale of the Droshky field (Gulf of Mexico).
Held for sale reflects a transfer to settled liabilities during 2019. This transfer was primarily related to the Droshky field
(Gulf of Mexico) which was considered held for sale at year-end 2018 and closed in the first quarter of 2019.
80
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
14. Leases
Supplemental balance sheet information related to leases was as follows:
(In millions)
Leases:
Right-of-use (“ROU”) asset
Balance Sheet Location:
Other noncurrent assets
Current portion of long-term lease liability Other current liabilities
Long-term lease liability
Deferred credits and other liabilities
December 31,
2020
2019
$
$
$
133 $
70 $
67 $
199
101
107
In determining our ROU assets and long-term lease liabilities, the lease standard requires certain accounting policy
decisions, while also providing a number of optional practical expedients for transition accounting. Our accounting policies and
the practical expedients utilized are summarized below:
•
•
•
•
Implemented an accounting policy to not recognize any right-of-use assets and lease liabilities related to short-term
leases on the balance sheet.
Implemented an accounting policy to not separate the lease and nonlease components for all asset classes, except for
vessels.
Elected the package of practical expedients which allows us to not reassess our prior conclusions regarding the lease
identification and lease classification for contracts that commenced or expired prior to the effective date.
Elected the practical expedient pertaining to land easements which allows us to continue accounting for existing
agreements under the previous accounting policies as nonlease transactions. Any modifications of existing contracts or
new agreements will be assessed under the new lease accounting guidance and may become leases in the future.
We enter into various lease agreements to support our operations including drilling rigs, well fracturing equipment,
compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these
transactions and the majority of our existing leases are classified as either short-term or long-term operating leases.
The majority of the drilling rig agreements and all of fracturing equipment agreements are classified as short-term leases
based on the noncancellable period for which we have the right to use the equipment and assessment of options present in each
agreement. We also incur variable lease costs under these agreements primarily related to chemicals and sand used in fracturing
operations or various additional on-demand equipment and labor. The lease costs associated with the drilling rigs and fracturing
equipment are primarily capitalized as part of the well costs.
Our long-term leases are comprised of compressors, buildings, drilling rigs, aircraft, vessels, vehicles and miscellaneous
field equipment. Our lease agreements may require both fixed and variable payments; none of the variable payments are rate or
index-based, therefore only fixed payments were considered for recognizing lease liabilities and ROU assets related to long-
term leases. Also, based on our election not to separate the lease and nonlease components, fixed payments related to
equipment, crew and other nonlease components are included in the initial measurement of lease liabilities and ROU assets for
all asset classes, except for vessels. For vessels, the contractual consideration was allocated between lease and nonlease
components based on estimates provided by service providers.
81
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease
liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities
and ROU assets are determined based on gross contractual obligations. As we use the leased assets for joint operations, we have
the contractual right to recover the other working interest owners’ share of lease costs. As a result, our lease costs are presented
on a net basis, reduced for any costs recoverable from other working interest owners. The table below presents our net lease
costs for the years ended December 31, 2020 and 2019 with the majority of operating lease costs expensed as incurred, while
the majority of the short-term and variable lease costs are capitalized into property, plant and equipment.
(In millions)
Lease costs:
Operating lease costs(a)
Short-term lease costs(b)
Variable lease costs(c)
Total lease costs
Other information:
Cash paid for amounts included in the measurement of operating lease
liabilities
ROU assets obtained in exchange for new operating lease liabilities(d)
Reductions to ROU assets resulting from modifications or cancellations
of operating leases
Year Ended
December 31, 2020
Year Ended
December 31, 2019
$
$
$
$
$
75 $
170
23
268 $
100 $
46 $
(68) $
84
321
107
512
100
293
—
(a)
(b)
(c)
(d)
Represents our net share of the ROU asset amortization and the interest expense.
Represents our net share of lease costs arising from leases of less than one year but longer than one month that were not included in the lease liability.
Represents our net share of variable lease payments that were not included in the lease liability.
Represents the cumulative value of ROU assets recognized at lease inception during the year of 2020. This amount is then amortized as we utilize the
ROU asset, the net effect of which is the ending ROU asset of $133 million (first table above).
We use our periodic incremental borrowing rate to discount future contractual payments to their present values. The
weighted average lease term and the discount rate relevant to long-term leases were two years and 3% as of December 31, 2020.
The remaining annual undiscounted cash flows associated with long-term leases and the reconciliation of these cash flows to
the lease liabilities recognized on the consolidated balance sheet is summarized below.
(In millions)
2021
2022
2023
2024
2025
Thereafter
Total undiscounted lease payments
Less: amount representing interest
Total operating lease liabilities
Less: current portion of long-term lease liability as of December 31, 2020
Long-term lease liability as of December 31, 2020
Operating Lease
Obligations
77
44
11
5
4
2
143
6
137
70
67
$
$
$
$
Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea,
which is occupied by EGHoldings, a related party equity method investee – see Note 24. The lease was classified as an
operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire
duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our
consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease
agreement are summarized below.
82
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
2021
2022
2023
2024
2025
Thereafter
Total undiscounted cash flows
Operating Lease
Future Cash Receipts
$
$
6
6
6
6
6
53
83
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in
Houston, Texas. The lessor and other participants are providing financing for up to $340 million, to fund the estimated project
costs, which was reduced effective August 2020, from $380 million to align with our revised estimate of the project costs. As of
December 31, 2020, project costs incurred totaled approximately $144 million. The initial lease term is five years and will
commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the
initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the
participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party.
The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.
15. Goodwill
Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances
indicate the fair value may have been reduced below its carrying value. During the first quarter of 2020, a global pandemic
caused a substantial deterioration in the worldwide demand of hydrocarbons. This demand loss resulted in a significant decline
in hydrocarbon prices. The commensurate decline in our market capitalization during the first quarter indicated that it was more
likely than not that the fair value of the International reporting unit was less than its carrying value.
We estimated the fair value of our International reporting unit using a combination of market and income approaches. The
market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our
enterprise value and valuation multiples of us and peers from the investor analyst community. The income approach utilized
discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future
liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable
reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The
assumptions used in the income approach are consistent with those that management uses to make business decisions. These
valuation methodologies represent Level 3 fair value measurements. Based on the results, we concluded our goodwill was fully
impaired, and recorded an impairment of $95 million in the consolidated statements of income for the first quarter of 2020.
The table below displays the allocated beginning goodwill balance of our International segment along with changes in the
carrying amount of goodwill for 2020 and 2019:
(In millions)
Beginning balance as of January 1, gross
Less: accumulated impairments
Beginning balance, net
Dispositions
Impairment
Ending balance as of December 30, net
December 31,
2020
2019
$
$
95 $
—
95
—
(95)
— $
97
—
97
(2)
—
95
83
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
16. Derivatives
See Note 17 for further information regarding the fair value measurement of derivative instruments. See Note 1 for
discussion of the types of derivatives we may use and the reasons for them. All of our commodity derivatives and interest rate
derivatives are/were subject to enforceable master netting arrangements or similar agreements under which we report net
amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with
where they appear on the consolidated balance sheets.
(In millions)
Not Designated as Hedges
Commodity
Commodity
Interest Rate
December 31, 2020
Asset
Liability
Net Asset
(Liability)
Balance Sheet Location
$
3 $
1 $
2 Other current assets
7
10
32
—
(25) Other current liabilities
10 Other noncurrent assets
Total Not Designated as Hedges
$
20 $
33 $
(13)
Cash Flow Hedges
Interest Rate
Interest Rate
Total Designated Hedges
Total
(In millions)
Not Designated as Hedges
Commodity
Commodity
Commodity
$
$
$
$
Total Not Designated as Hedges
$
Cash Flow Hedges
Interest Rate
Total Designated Hedges
Total
$
$
$
Derivatives Not Designated as Hedges
Commodity Derivatives
19 $
—
19 $
39 $
— $
16
16 $
49 $
19 Other noncurrent assets
(16) Deferred credits and other liabilities
3
(10)
December 31, 2019
Asset
Liability
Net Asset
(Liability)
Balance Sheet Location
9 $
1
—
10 $
2 $
2 $
12 $
1 $
—
5
6 $
— $
— $
6 $
8 Other current assets
1 Other noncurrent assets
(5) Other current liabilities
4
2 Other noncurrent assets
2
6
We have entered into multiple crude oil, natural gas and NGL derivatives indexed to the respective indices as noted in the
table below, related to a portion of our forecasted United States sales through 2021. These derivatives consist of three-way
collars, two-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. Three-way collars consist of a sold call
(ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes; the
floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive
the NYMEX WTI price plus the difference between the floor and the sold put price. Two-way collars only consist of a sold call
(ceiling) and a purchased put (floor). These crude oil, natural gas and NGL derivatives were not designated as hedges.
84
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table sets forth outstanding derivative contracts as of December 31, 2020 and the weighted average prices
for those contracts:
First Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
2021
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)
Weighted average price per Bbl:
Ceiling
Floor
Sold put
NYMEX WTI Two-Way Collars
Volume (Bbls/day)
Weighted average price per Bbl:
Ceiling
Floor
Basis Swaps - NYMEX WTI / ICE Brent (a)
Volume (Bbls/day)
Weighted average price per Bbl
Basis Swaps - NYMEX WTI / UHC (b)
Volume (Bbls/day)
Weighted average price per Bbl
NYMEX Roll Basis Swaps
Volume (Bbls/day)
Weighted average price per Bbl
Natural Gas
Henry Hub (“HH”) Two-Way Collars
Volume (MMBtu/day)
Weighted average price per MMBtu:
Ceiling
Floor
HH Fixed Price Swaps
Volume (MMBtu/day)
Weighted average price per MMBtu
NGL
Fixed Price Propane Swaps (c)
Volume (Bbls/day)
$
$
$
$
$
$
$
$
$
$
$
—
—
—
—
$
$
$
10,000
58.72
37.00
27.00
$
$
$
—
—
—
—
$
$
$
—
—
—
—
90,000
50,000
30,000
30,000
51.86
35.44
$
$
52.98
35.80
$
$
51.54
35.67
$
$
51.54
35.67
3,278
(7.24) $
—
—
$
14,000
14,000
(1.80) $
(1.80) $
50,000
(0.13) $
50,000
$
(0.13) $
—
—
—
—
—
—
$
$
$
$
—
—
—
—
—
—
250,000
200,000
200,000
200,000
3.14
2.52
$
$
3.05
2.50
$
$
3.05
2.50
$
$
50,000
50,000
50,000
2.88
$
2.88
$
2.88
$
5,000
5,000
5,000
3.05
2.50
50,000
2.88
5,000
23.19
Weighted average price per Bbl
$
23.19
$
23.19
$
23.19
$
(a)
(b)
(c)
The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.
The basis differential price is indexed against U.S. Sweet Clearbrook (“UHC”) and NYMEX WTI.
The fixed price propane swap is priced at Mont Belvieu Spot Gas Liquids Prices: Non-TET Propane.
85
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table sets forth outstanding derivative contracts entered into between January 1, 2021 and February 15,
2021, and the weighted average prices for those contracts.
Crude Oil
Basis Swaps - NYMEX WTI / UHC (a)
Volume (Bbls/day)
Weighted average price per Bbl
NYMEX WTI Three-Way Collars
Volume (Bbls/day)
Weighted average price per Bbl:
Ceiling
Floor
Sold put
WTI Fixed Price Swaps
Volume (Bbls/day)
Weighted average price per Bbl
2021
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
344
1,000
$
(1.80) $
(1.80) $
—
— $
—
30,000
10,000
$
$
$
— $
62.36 $
65.18 $
— $
40.67 $
45.00 $
— $
30.67 $
35.00 $
20,000
$
50.35 $
—
— $
—
— $
—
—
—
—
—
—
—
—
(a)
The basis differential price is indexed against U.S. Sweet Clearbrook (“UHC”) and NYMEX WTI.
The mark-to-market impact and settlement of these commodity derivative instruments appears in the table below and is
reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.
(In millions)
Unrealized mark-to-market gain (loss)
Net settlements of commodity derivative instruments
Year Ended December 31,
2020
2019
2018
$
$
(27) $
143 $
(124) $
52 $
267
(281)
86
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Interest Rate Swaps
During 2020, we entered into forward starting interest rate swaps to hedge the variations in cash flows as a result of
fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of
a future debt issuance in 2022. Each respective derivative contract can be tied to an anticipated underlying dollar notional
amount. During the third quarter of 2020, we de-designated these forward starting interest rate swaps previously designated as
cash flow hedges. At December 31, 2020, accumulated other comprehensive income included a net deferred loss of $2 million
related to the de-designated forward starting interest rate swaps previously designated as cash flow hedges. No portion of this
amount has been reclassified from accumulated other comprehensive income as of December 31, 2020. We expect to reclassify
this amount into earnings as an adjustment to net interest and other upon the occurrence of the forecasted transactions.
The following table presents, by maturity date, information about our de-designated forward starting interest rate swap
agreements, including the rate.
December 31, 2020
December 31, 2019
Maturity Date
Aggregate Notional
Amount
(in millions)
Weighted Average,
LIBOR
Aggregate Notional
Amount
(in millions)
Weighted Average,
LIBOR
November 1, 2022
$
500
0.99 % $
—
— %
The following table sets forth the net impact of the forward starting interest rate swap derivatives de-designated as cash
flow hedges on other comprehensive income (loss).
(In millions)
Interest Rate Swaps
Year Ended December 31, 2020
Beginning balance
Change in fair value recognized in other comprehensive income (loss)
Ending balance
$
$
—
(2)
(2)
Derivatives Designated as Cash Flow Hedges
During 2020, we entered into forward starting interest rate swaps with a notional amount of $350 million to hedge
variations in cash flows arising from fluctuations in the LIBOR benchmark interest rate related to forecasted interest payments
of a future debt issuance in 2025. We expect to refinance these debt maturities in 2025. The swaps will terminate on or prior to
the refinancing of the debt and the final value will be reclassified from accumulated other comprehensive income into earnings
with each future interest payment.
During 2019, we entered into forward starting interest rate swaps with a total notional amount of $320 million to hedge
variations in cash flows related to the 1-month London Interbank Offered Rate (“LIBOR”) component of future lease payments
of our future Houston office. These swaps will settle monthly on the same day the lease payment is made with the first swap
settlement occurring in January 2022. We expect the first lease payment to commence sometime in the period from December
2021 to May 2022. The last swap will mature in September 2026. See Note 14 for further details regarding the lease of the new
Houston office.
The following table presents information about our interest rate swap agreements, including the weighted average LIBOR-
based, fixed rate.
Maturity Date
June 1, 2025
September 9, 2026
December 31, 2020
December 31, 2019
Aggregate Notional
Amount
(in millions)
Weighted
Average, LIBOR
Aggregate Notional
Amount
(in millions)
Weighted
Average, LIBOR
$
$
350
320
0.95 % $
1.51 % $
—
320
— %
1.51 %
At December 31, 2020, accumulated other comprehensive income included deferred gains of $2 million related to forward
starting interest rate swaps designated as cash flow hedges. No amounts related to these swaps are expected to impact the
consolidated statements of income in the next 12 months.
87
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
17. Fair Value Measurements
Fair Values – Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2020
and 2019 by hierarchy level.
(In millions)
Derivative instruments, assets
Interest rate - not designated as cash flow hedges
Interest rate - designated as cash flow hedges
Derivative instruments, assets
Derivative instruments, liabilities
Commodity(a)
Interest rate - designated as cash flow hedges
Derivative instruments, liabilities
Total
(In millions)
Derivative instruments, assets
Commodity(a)
Interest rate - designated as cash flow hedges
Derivative instruments, assets
Derivative instruments, liabilities
Commodity(a)
Derivative instruments, liabilities
December 31, 2020
Level 1
Level 2
Level 3
Total
$
$
$
$
$
$
$
$
$
$
— $
—
— $
— $
—
— $
— $
10 $
19
29 $
(23) $
(16)
(39) $
(10) $
— $
—
— $
— $
—
— $
— $
December 31, 2019
Level 1
Level 2
Level 3
Total
— $
—
— $
(3) $
(3) $
(3) $
7 $
2
9 $
— $
— $
9 $
— $
—
— $
— $
— $
— $
10
19
29
(23)
(16)
(39)
(10)
7
2
9
(3)
(3)
6
Total
(a)
Derivative instruments are recorded on a net basis in our consolidated balance sheet (See Note 16).
Commodity derivatives include three-way collars, two-way collars, fixed price swaps, basis swaps and NYMEX roll basis
swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For
swaps, inputs to the models include only commodity prices and interest rates and are categorized as Level 1 because all
assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars and two-
way collars, inputs to the models include commodity prices, and implied volatility and are categorized as Level 2 because
predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes,
which are Level 2 inputs. See Note 16 for details on the forward starting interest swaps.
Fair Values – Goodwill
See Note 15 for detail information relating to goodwill.
Fair Values – Nonrecurring
See Note 5 and Note 12 for detail on our fair values for nonrecurring items, such as impairments.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, the current
portion of our long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair
value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the
instruments, (2) our credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense,
which includes an evaluation of counterparty credit risk.
88
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table summarizes financial instruments, excluding receivables, payables and derivative financial
instruments, and their reported fair values by individual balance sheet line item at December 31, 2020 and 2019.
(In millions)
Financial assets
Current assets
Other noncurrent assets
Total financial assets
Financial liabilities
Other current liabilities
Long-term debt, including current portion(a)
Deferred credits and other liabilities
Total financial liabilities
(a)
Excludes debt issuance costs.
December 31,
2020
2019
Fair
Value
Carrying
Amount
Fair
Value
Carrying
Amount
$
$
$
$
4 $
24
28 $
4 $
37
41 $
4 $
26
30 $
72 $
103 $
62 $
6,077
103
5,431
76
6,174
99
6,252 $
5,610 $
6,335 $
4
38
42
90
5,529
86
5,705
Fair values of our notes receivable and our financial assets included in other noncurrent assets, and of our financial
liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach
and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted
using a rate deemed appropriate to obtain the fair value.
All of our long-term debt instruments are publicly traded. A market approach, based upon quotes from major financial
institutions, which are Level 2 inputs, is used to measure the fair value of our debt.
18. Debt
Revolving Credit Facility
As of December 31, 2020, we had no borrowings on our $3.0 billion unsecured revolving credit facility (“Credit Facility”).
The Credit Facility matures on May 28, 2023 and we retain the ability to request two one-year extensions of the maturity date.
The Credit Facility includes a single financial covenant requiring that our ratio of total debt to total capitalization not
exceed 65% as of the last day of each fiscal quarter. This covenant calculation was modified in December 2020, when we
executed the fifth amendment to our credit facility. The primary changes resulting from this amendment are (i) a modification
to the debt to total capitalization covenant calculation that permits an add-back to shareholders’ equity for certain non-cash
write-downs, (ii) the addition of certain customary events of default, including a cross payment event of default and (iii) certain
restrictions on the incurrence of subsidiary indebtedness. Under the amended definition, our total debt to total capitalization
ratio was 26% at December 31, 2020.
If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under
the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all
outstanding letters of credit under the Credit Facility.
89
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Long-term debt
The following table details our long-term debt:
(In millions)
Senior unsecured notes:
2.800% notes due 2022(a)
9.375% notes due 2022(b)
Series A notes due 2022(b)
8.500% notes due 2023(b)
8.125% notes due 2023(b)
3.850% notes due 2025(a)
4.400% notes due 2027(a)
6.800% notes due 2032(a)
6.600% notes due 2037(a)
5.200% notes due 2045(a)
Bonds:(c)
2.00% bonds due 2037
2.10% bonds due 2037
2.20% bonds due 2037
2.125% bonds due 2037
2.375% bonds due 2037
Total(b)
Unamortized discount
Unamortized debt issuance cost
December 31,
2020
2019
$
500 $
1,000
32
3
70
131
900
32
3
70
131
900
1,000
1,000
550
750
500
200
200
200
200
200
5,436
(5)
(27)
5,404 $
$
550
750
500
200
200
200
—
—
5,536
(7)
(28)
5,501
Total long-term debt
(a)
(b)
These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.
In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2020 may be declared
immediately due and payable.
(c) Mandatory purchase dates for these bonds: April 1, 2023 for the 2.00% bonds; July 1, 2024 for the 2.10% bonds; July 1, 2026 for the 2.20% bonds; July
1, 2024 for the 2.125% bonds; and July 1, 2026 for the 2.375% bonds. Subsequent to the various mandatory purchase dates, we will also have the right to
convert and remarket these any time up to the 2037 maturity date.
The following table shows future debt payments:
(In millions)
2021
2022
2023
2024
2025
Thereafter
Total long-term debt, including current portion
Debt Remarketing
$
$
—
535
401
400
900
3,200
5,436
On August 18, 2020, we closed a $400 million remarketing to investors of sub-series B bonds which are part of the
$1 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017.
Debt Repurchases
In October 2020, we repurchased $500 million of our 2.8% Senior Notes due 2022 (“2022 Notes”). The remaining $500
million of the 2022 Notes is included in long-term debt on our consolidated balance sheet as of December 31, 2020.
90
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
19. Incentive Based Compensation
Description of stock-based compensation plans – The Marathon Oil Corporation 2019 Incentive Compensation Plan (the
“2019 Plan”) was approved by our stockholders in May 2019 and authorizes the Compensation Committee of the Board of
Directors to grant stock options, stock appreciation rights (“SARs”), stock awards (including restricted stock and restricted
stock unit awards), performance unit awards and cash awards to employees. The 2019 Plan also allows us to provide equity
compensation to our non-employee directors. No more than 27.9 million shares of our common stock may be issued under the
2019 Plan. In connection with the granting of an award under the 2019 Plan, the number of shares available for issuance under
the 2019 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted, except
the awards that by their terms do not permit settlement in shares of our common stock will not reduce the number of shares of
common stock available for issuance under the 2019 Plan.
Shares subject to awards under the 2019 Plan that are forfeited, terminated or expire unexercised become available for
future grants. In addition, the number of shares of our common stock reserved for issuance under the 2019 Plan will not be
increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax
withholding obligations. Shares issued as a result of awards granted under the 2019 Plan are generally funded out of common
stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
After approval of the 2019 Plan, no new grants were or will be made from any prior plans. Any awards previously granted
under any prior plans shall continue to be exercisable in accordance with their original terms and conditions.
Stock-based awards under the plans
Stock options – We grant stock options under the 2019 Plan. Our stock options represent the right to purchase shares of our
common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period
and have a maximum term of ten years from the date they are granted.
SARs – At December 31, 2020, there are no SARs outstanding.
Restricted stock – We grant restricted stock under the 2019 Plan. The restricted stock awards granted to officers generally
vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to
certain non-officer employees based on their performance within certain guidelines and for retention purposes. The restricted
stock awards to non-officers generally vest ratably over a three-year period, contingent on the recipient’s continued
employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The
non-vested shares of restricted stock are not transferable and are held by our transfer agent.
Stock-based performance units – We grant stock-based performance units to officers under the 2019 Plan. At the grant
date, each unit represents the value of one share of our common stock. These units are settled in shares, and the number of
shares of our common stock to be paid is based on the vesting percentage, which can be from zero to 200% based on
performance achieved over a three-year performance period, and as determined by the Compensation Committee of the Board
of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer
companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the
performance period and would be paid in cash at the end of the performance period based on the amount of dividends credited
generally over the performance period on shares of our common stock that represent the value of the units granted multiplied by
the vesting percentage.
Restricted stock units – We maintain an equity compensation program for our non-employee directors. All non-employee
directors receive annual grants of common stock units. Any units granted prior to 2012 must be held until completion of board
service, at which time the non-employee director will receive common shares. For units granted between 2012 and 2016,
common shares will generally vest following completion of board service or three years from the date of grant, whichever is
earlier. For awards issued in 2017 and later, directors may elect to defer settlement of their common stock units until after they
cease serving on the Board. Absent such an election to defer, common shares will vest upon the earlier of three years from the
date of grant or completion of board service. Under the 2019 Plan, we also grant restricted stock units to officers, which
generally vest three years from the date of the grant and restricted stock units to certain non-officer employees, which generally
vest ratably over a three-year period. Both awards are contingent on the recipient’s continued employment. Grants of restricted
stock units to these non-officer employees are generally based on their performance and for retention purposes. Common shares
will be issued for these restricted stock units after vesting. Prior to vesting, recipients of restricted stock units typically receive
dividend equivalent payments, but they may not vote.
Total stock-based compensation expense – Total employee stock-based compensation expense was $55 million, $60
million and $53 million in 2020, 2019 and 2018. Due to the full valuation allowance on our net federal deferred tax assets, we
recognized no tax benefit during these years. Cash received upon exercise of stock option awards was less than $1 million in
91
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2020 and $1 million and $26 million in 2019 and 2018, respectively. There were no tax benefits recognized for deductions for
stock awards settled during 2020, 2019 and 2018.
Stock option awards – During 2020, 2019 and 2018 we granted stock option awards to officer employees. The weighted
average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:
2020
2019
2018
Exercise price per share
Expected annual dividend yield
Expected life in years
Expected volatility
Risk-free interest rate
$
10.47
$
16.79 $
1.9 %
6.14
44 %
1.5 %
1.2 %
5.82
43 %
2.5 %
Weighted average grant date fair value of stock option awards granted
$
3.82
$
6.62 $
The following is a summary of stock option award activity in 2020.
14.52
1.4 %
6.45
43 %
2.8 %
5.83
Number of
Shares
Weighted
Average Exercise
Price
Weighted Average
Remaining
Contractual Term
Aggregate
Intrinsic Value
(in millions)
Outstanding at beginning of year
Granted
Exercised
Canceled
Outstanding at end of year
Exercisable at end of year
Expected to vest
5,659,731 $
1,132,808 $
(52,333) $
(725,951) $
6,014,255 $
4,219,975 $
1,766,804 $
23.55
10.47
7.22
25.44
21.00
24.63
12.50
5 years
4 years
9 years
$
$
—
—
The intrinsic value of stock option awards exercised during 2018 was $13 million while it was immaterial during 2020 and
2019.
As of December 31, 2020, unrecognized compensation cost related to stock option awards was $4 million, which is
expected to be recognized over a weighted average period of 1 year.
Restricted stock awards and restricted stock units – The following is a summary of restricted stock and restricted stock
unit award activity in 2020.
Unvested at beginning of year
Granted
Vested
Canceled
Unvested at end of year
Awards
Weighted Average
Grant Date Fair Value
7,174,386
$
$
5,390,960
(3,127,762) $
(1,585,830) $
$
7,851,754
15.88
8.50
15.76
11.65
11.72
The vesting date fair value of restricted stock awards which vested during 2020, 2019 and 2018 was $49 million, $48
million and $48 million. The weighted average grant date fair value of restricted stock awards was $11.72, $15.88 and $14.04
for awards unvested at December 31, 2020, 2019 and 2018.
As of December 31, 2020 there was $48 million of unrecognized compensation cost related to restricted stock awards
which is expected to be recognized over a weighted average period of 1 year.
Stock-based performance unit awards – During 2020, 2019 and 2018 we granted 1,038,676, 656,636 and 754,140 stock-
based performance unit awards to officers. At December 31, 2020, there were 1,658,088 units outstanding. Total stock-based
performance unit awards expense was $5 million, $7 million and $13 million in 2020, 2019 and 2018.
92
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units
granted in 2020, 2019 and 2018 were:
Valuation date stock price
Expected annual dividend yield
Expected volatility
Risk-free interest rate
Fair value of stock-based performance units outstanding
(a)
Represents key assumptions at grant date, as 2020 and 2019 performance unit awards are settled in stock.
2020(a)
10.47
$
2019(a)
2018
$
16.79
$
13.69
1.9 %
39 %
1.4 %
1.2 %
43 %
2.5 %
1.5 %
41 %
1.5 %
$
10.55
$
20.66
$
17.29
20. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees. Benefits under
these plans are based on plan provisions specific to each plan.
We also had a noncontributory defined benefit pension plan covering eligible U.K. employees that was transferred to the
buyer in connection with the sale of our U.K. business during 2019. See Note 5 for further information on this disposition.
During the year ended December 31, 2019, we reclassified $20 million from accumulated other comprehensive income to
pension assets upon remeasurement of the plan.
We also have plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided up to
age 65 through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features.
Post-65 retiree health care benefits have been provided to certain U.S. employees on a defined contribution basis; this program
terminated effective as of December 31, 2020. Life insurance benefits are provided to certain retiree beneficiaries. These other
postretirement benefits are not funded in advance. Employees hired after 2016 are not eligible for any postretirement health care
or life insurance benefits.
Obligations and funded status – The following summarizes the obligations and funded status for our defined benefit
pension and other postretirement plans.
93
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
Accumulated benefit obligation
Change in pension benefit obligations:
Beginning balance
Service cost
Interest cost
Plan amendment
Divestiture(a)
Actuarial loss
Foreign currency exchange rate changes
Gain due to curtailment(a)
Settlements paid
Benefits paid
Ending balance
Change in fair value of plan assets:
Beginning balance
Actual return on plan assets
Employer contributions
Foreign currency exchange rate changes
Divestiture(b)
Settlements paid
Benefits paid
Ending balance
Funded status of plans at December 31
Amounts recognized in the consolidated balance sheets:
Noncurrent assets
Current liabilities
Noncurrent liabilities
Accrued benefit cost
Pension Benefits
2020
2019
U.S.
Int’l
U.S.
Int’l
Other Benefits
2020
U.S.
2019
U.S.
$
298 $
— $
343 $
— $
80 $
89
$
354 $
— $
326 $
511 $
89 $
19
9
—
—
36
—
(1)
(104)
(5)
—
—
—
—
—
—
—
—
—
19
12
—
—
48
—
—
(45)
(6)
—
8
—
(549)
36
6
—
—
1
2
—
—
4
—
—
—
(12)
(16)
$
308 $
— $
354 $
— $
80 $
$
236 $
— $
203 $
594 $
— $
18
49
—
—
(104)
(5)
—
—
—
—
—
—
44
40
—
—
(45)
(6)
68
8
8
(666)
—
(12)
194 $
— $
236 $
(114) $
— $
(118) $
— $
— $
—
16
—
—
—
(16)
— $
(80) $
— $
— $
— $
— $
— $
(4)
(110)
—
—
(6)
(112)
—
—
(10)
(70)
$
$
$
$
(114) $
— $
(118) $
— $
(80) $
96
1
3
—
—
9
—
—
—
(20)
89
—
—
20
—
—
—
(20)
—
(89)
—
(18)
(71)
(89)
Pretax amounts in accumulated other comprehensive
loss:
Net loss
Prior service credit
$
72 $
— $
85 $
— $
24 $
23
(19)
—
(29)
—
(97)
(129)
(a)
(b)
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
Refer to Note 5 for further information on the sale of our U.K. business.
The pension and postretirement plans each experienced net actuarial losses in 2020. A decrease in discount rate used to
measure the plans, which increased their respective benefit obligations, was the primary source of the actuarial losses.
94
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Components of net periodic benefit costs and other comprehensive (income) loss – The following summarizes the net
periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and
other postretirement plans.
Pension Benefits
Other Benefits
Year Ended December 31,
Year Ended December 31,
2020
U.S.
2019
2018
U.S.
Int’l
U.S.
Int’l
2020
U.S.
2019
U.S.
2018
U.S.
9
(11)
(6)
9
30
$
19 $
19 $ — $
18 $ — $
1 $
1 $
12
(10)
8
(11)
12
(11)
14
2
3
(24)
—
—
—
2
7
(7)
—
(10)
—
7
—
12
—
11
18
—
(18)
2
(19)
1
(8)
1
3
—
—
—
(3)
—
—
—
—
(14)
—
—
$
47 $
33 $
(3) $
38 $
(7) $
(27) $
(14) $
2
(In millions)
Components of net periodic benefit costs:
Service cost
Interest cost
Expected return on plan assets
Amortization:
- prior service credit
- actuarial loss
Net settlement loss(a)
Net curtailment gain(b)
Net periodic benefit cost (credit) (c)
Other changes in plan assets and benefit obligations
recognized in other comprehensive (income) loss
(pretax):
Actuarial loss (gain)
$
27 $
14 $
(21) $
(4) $
8 $
4 $
9 $
(15)
Settlement loss and amortization of actuarial gain
(loss)
Prior service cost (credit)
Curtailment gain and amortization of prior service
credit (cost)
Total recognized in other comprehensive (income) loss
Total recognized in net periodic benefit cost and other
comprehensive (income) loss
(40)
(19)
(41)
(29)
(3)
(2)
(1)
—
—
—
—
3
—
—
(1)
(99)
10
7
(6)
10
—
32
19
8
$
$
(3) $
2 $
(68) $
(23) $
8 $
34 $
27 $ (107)
44 $
35 $
(71) $
15 $
1 $
7 $
13 $ (105)
(a)
(b)
(c)
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan’s total service and
interest costs for that year.
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.
Net periodic benefit costs (credits) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
95
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31,
and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2020, 2019 and 2018.
(In millions)
Weighted average assumptions used to determine benefit
obligation:
Discount rate
Rate of compensation increase(a)
Cash balance interest crediting
Weighted average assumptions used to determine net periodic
benefit cost:
Discount rate
Pension Benefits
Other Benefits
2020
U.S.
2019
U.S.
2018
U.S.
Int’l
2020
U.S.
2019
U.S.
2018
U.S.
2.52 % 3.13 % 4.26 % 2.90 % 2.02 % 2.91 % 4.09 %
0.50 % 4.50 % 4.00 %
— % 0.50 % 4.50 % 4.00 %
3.00 % 3.00 % 3.26 %
— %
— %
— %
— %
2.90 % 3.70 % 3.88 % 2.50 % 2.63 % 4.09 % 3.54 %
Expected long-term return on plan assets
6.00 % 6.25 % 6.50 % 3.70 %
— %
— %
— %
Rate of compensation increase
Cash balance interest crediting
4.50 % 4.00 % 4.00 %
— % 4.50 % 4.00 % 4.00 %
3.00 % 3.00 % 3.00 %
— %
— %
— %
— %
(a)
The assumed rate of compensation increase is 0.50% for the year 2021 and 4.50% for future years.
Expected long-term return on plan assets – The expected long-term return on plan assets assumption for our U.S. pension
plan is determined based on an internally developed asset rate-of-return modeling tool which utilizes underlying assumptions
based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation. The
expected return for each asset category is then weighted based on the actual asset allocation to develop the overall expected
long-term return on plan assets assumption.
Assumed weighted average health care cost trend rates
Employer provided subsidies for post-65 retiree health care coverage were frozen effective January 1, 2017 at January 1,
2016 established amount levels. Company contributions are funded to a Health Reimbursement Account on the retiree’s behalf
to subsidize the retiree’s cost of obtaining health care benefits through a private exchange (the “post-65 retiree health benefits”).
In the fourth quarter of 2018, we terminated the post-65 retiree health benefits effective as of December 31, 2020. The
post-65 retiree health benefits will no longer be provided after that date. In addition, the pre-65 retiree medical coverage subsidy
was frozen as of January 1, 2019, and the ability for retirees to opt in and out of this coverage, as well as pre-65 retiree dental
and vision coverage, was also eliminated. Retirees must enroll in connection with retirement for such coverage, or they lose
eligibility. These plan changes reduced our retiree medical benefit obligation by approximately $99 million at December 31,
2018.
Plan investment policies and strategies – The investment policies for our U.S. pension plan assets reflect the funded status
of the plan and expectations regarding our future ability to make further contributions. Long-term investment goals are to:
(1) manage the assets in accordance with applicable legal requirements; (2) produce investment returns which meet or exceed
the rates of return achievable in the capital markets while maintaining the risk parameters set by the plan’s investment
committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term
risk/return orientation. Investment performance and risk is measured and monitored on an ongoing basis through quarterly
investment meetings and periodic asset and liability studies.
U.S. plan – The plan’s current targeted asset allocation is comprised of 55% equity securities and 45% other fixed income
securities. Over time, as the plan’s funded ratio (as defined by the investment policy) improves, in order to reduce volatility in
returns and to better match the plan’s liabilities, the allocation to equity securities will decrease while the amount allocated to
fixed income securities will increase. The plan’s assets are managed by a third-party investment manager.
International plan – As mentioned above, the plan covering eligible U.K. employees that was transferred to the buyer in
connection with the sale of our U.K. business during 2019.
Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation
techniques employed for each major plan asset class at December 31, 2020 and 2019.
Cash and cash equivalents – Cash and cash equivalents are valued using a market approach and are considered Level 1.
Equity securities – Investments in common stock are valued using a market approach at the closing price reported in an
active market and are therefore considered Level 1. Private equity investments include interests in limited partnerships which
96
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a
combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and
estimated performance incentives. These private equity investments are considered Level 3.
Fixed income securities – Fixed income securities are valued using a market approach. U.S. treasury notes and exchange
traded funds (“ETFs”) are valued at the closing price reported in an active market and are considered Level 1. Corporate bonds,
private placements and GNMA/FNMA/FHLMC pools are valued using calculated yield curves created by models that
incorporate various market factors. Primarily investments are held in U.S. and non-U.S. corporate bonds in diverse industries
and are considered Level 2. Forward contracts included under government securities are traded in the over-the-counter market
and occur between two parties only with no intermediary. The details of each contract such as trade size, price and maturity are
tailored to each security and negotiated between the two parties, as such, these investments are considered Level 3. Other fixed
income investments include zero coupon and interest rate swaps.
Other – Other investments are comprised of an unallocated annuity contract, two limited liability companies and real
estate. All are considered Level 3, as significant inputs to determine fair value are unobservable.
Commingled funds – The investment in the commingled funds are valued using the net asset value of units held as a
practical expedient. The commingled funds consist of equity and fixed income portfolios with underlying investments held in
U.S. and non-U.S. securities.
The following tables present the fair values of our defined benefit pension plan’s assets, by level within the fair value
hierarchy, as of December 31, 2020 and 2019.
(In millions)
Equity securities:
Common stock
Private equity
Other
Total investments, at fair value
Commingled funds(a)
Total investments
(In millions)
Cash and cash equivalents(b)
Equity securities:
Common stock
Private equity
Fixed income securities:
Corporate
Exchange traded funds
Government
Other
Total investments, at fair value
Commingled funds(a)
Total investments
(a)
Level 1
December 31, 2020
Level 3
Level 2
Total
$
61 $
—
—
61
—
— $
—
—
—
—
— $
8
18
26
—
$
61 $
— $
26 $
61
8
18
87
107
194
December 31, 2019
Level 1
Level 2
Level 3
U.S.
U.S.
U.S.
Total
U.S.
$
(7) $
— $
— $
(7)
75
—
—
3
31
—
102
—
102 $
—
—
2
—
11
—
13
—
13 $
—
10
—
—
5
18
33
—
33 $
75
10
2
3
47
18
148
88
236
$
After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net
asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.
The negative cash balance was due to the timing of when investment trades occur and when they settle.
(b)
The activity during the year ended December 31, 2020 and 2019, for the assets using Level 3 fair value measurements was
immaterial.
97
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Cash flows
Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial
assumptions applied at December 31, 2020 and reflect expected future services, as appropriate, are to be paid in the years
indicated.
(In millions)
2021
2022
2023
2024
2025
2026 through 2030
Pension Benefits
Other Benefits
$
$
31 $
28
27
25
23
104 $
10
9
8
7
6
23
Contributions to defined benefit plans – We expect to make contributions to the funded pension plan of up to $40 million in
2021. Cash contributions to be paid from our general assets for the unfunded portion of our pension and postretirement plans
are expected to be approximately $3 million and $10 million in 2021.
Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees.
Contributions to these plans totaled $13 million, $18 million and $22 million in 2020, 2019 and 2018.
21. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss):
(In millions)
Postretirement and postemployment plans
Amortization of prior service credit
Amortization of actuarial loss
Net settlement loss
Net curtailment gain
Other
U.K pension plan transferred to buyer (a)(b)
Foreign currency translation adjustment related
to sale of U.K. business(b)
Income taxes related to sale of U.K. business (b)
Other insignificant items
Total reclassifications to expense, net of tax (c)
$
Year Ended December 31,
2020
2019
Income Statement Line
$
24 $
(11)
(30)
26
(8)
(12)
17
—
—
—
—
—
—
— $
—
6 Other net periodic benefit credits
83
30
(45)
68 Net gain on disposal of assets
1 Net interest and other
75 Net income
(a)
(b)
(c)
See Note 20 for detail on the U.K. pension plan.
See Note 5 for detail on the U.K. disposition.
During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets in the U.S. and as such, there is no tax impact to our
postretirement and postemployment plans other than on the sale of the U.K. business.
98
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
22. Supplemental Cash Flow Information
(In millions)
Included in operating activities:
Year Ended December 31,
2020
2019
2018
Interest paid, net of amounts capitalized
Income taxes paid to (received from) taxing authorities, net of refunds(a)
$
251 $
(51)
253 $
73
255
287
Noncash investing activities:
Increase (decrease) in asset retirement costs
Asset retirement obligations assumed by buyer(b)
2020, 2019 and 2018 includes $94 million, $90 million and $37 million, related to tax refunds.
In 2019, our dispositions include the sale of the Droshky field (Gulf of Mexico), the sale of our non-operated interest in the Atrush block in Kurdistan and
the sale of our U.K. business. See Note 5 for further detail on dispositions.
80 $
— $
1,082
(183)
82
—
$
(a)
(b)
Other noncash investing activities include accrued capital expenditures as of December 31, 2020, 2019 and 2018 of $95
million, $288 million and $250 million.
23. Other Items
Net interest and other
(In millions)
Interest:
Interest income
Interest expense
Income on interest rate swaps
Total interest
Other:
Net foreign currency gain
Other
Total other
Net interest and other
Year Ended December 31,
2019
2018
2020
$
$
5 $
(279)
12
(262)
—
6
6
(256) $
25 $
(280)
—
(255)
4
7
11
(244) $
32
(280)
—
(248)
9
13
22
(226)
Foreign currency – Aggregate foreign currency gains were included in the consolidated statements of income as follows:
(In millions)
Net interest and other
Provision for income taxes
Aggregate foreign currency gains
Year Ended December 31,
2019
2018
2020
$
$
— $
—
— $
4 $
2
6 $
9
10
19
99
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
24. Equity Method Investments
During 2020, 2019 and 2018 our equity method investees were considered related parties and included:
•
•
•
EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.
Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.
AMPCO, in which we have a 45% noncontrolling interest. AMPCO is engaged in methanol production activity.
Our equity method investments are summarized in the following table:
(In millions)
EGHoldings
Alba Plant LLC
AMPCO
Total
Ownership as of
December 31,
December 31, 2020
2020
2019
60%
52%
45%
$
$
113 $
168
166
447 $
310
163
190
663
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a
return of capital previously contributed) were $49 million in 2020, $105 million in 2019 and $270 million in 2018.
During the year ended December 31, 2020, we recorded impairments of $171 million to an investment in an equity method
investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. See
Note 12 to the consolidated financial statements for further information on the equity method investee impairment.
Summarized financial information for equity method investees is as follows:
(In millions)
Income data – year:
Revenues and other income
Income (loss) from operations
Net income (loss)
Balance sheet data – December 31:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
2020
2019
2018
$
$
586 $
16
(3)
389 $
941
235
170
832 $
250
187
455
1,049
284
183
1,269
588
459
Revenues from related parties were $38 million, $42 million and $48 million in 2020, 2019 and 2018, respectively, with
the majority related to EGHoldings in all years.
Current receivables from related parties at December 31, 2020 and 2019 were $24 million and $28 million, with the
majority related to EGHoldings in 2020 and EGHoldings and Alba Plant LLC for 2019. Payables to related parties were $13
million and $11 million at December 31, 2020 and 2019, respectively, with the majority related to Alba Plant LLC in both
periods.
25. Stockholders’ Equity
During 2020, we acquired approximately 9 million of common shares at a cost of $85 million, which are held as treasury
stock. During 2019, we acquired 24 million of common shares at a cost of $345 million under the same program. As of
December 31, 2020 the total remaining share repurchase authorization was $1.3 billion. 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 or proceeds from potential asset sales. This program may be
changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.
The repurchase program does not include specific price targets or timetables.
100
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
26. Commitments and Contingencies
In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned
subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta
Europa, E.G. Our equity method investee, Alba Plant LLC, is also a party to some of the agreements. These agreements contain
clauses that require MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and
damage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant and certain
environmental liabilities arising from certain hydrocarbons in the custody of Alba Plant LLC. Pursuant to these agreements,
MEGPL agreed to indemnify third party property or events, including environmental liabilities, injury to Alba Plant LLC’s
personnel and damage to or loss of Alba Plant LLC’s automobiles. At this time, we cannot reasonably estimate this obligation
as we do not have any history of prior indemnification claims or environmental discharge or contamination. Therefore, we have
not recorded a liability with respect to these indemnities since the amount of potential future payments under these
indemnification clauses is not determinable.
The agreements to process the third-party Alen Unit gas required the execution of third-party guarantees by Marathon Oil
Corporation in favor of the Alen Unit’s owners. Two separate guarantees were executed during the second quarter of 2020; one
for a maximum of $91 million pertaining to the payment obligations of Equatorial Guinea LNG Operations, S.A. and another
for a maximum of $25 million pertaining to the payment obligations of Alba Plant LLC. Payment by us would be required if
either of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen
Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG
Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We measured these guarantees
at fair value using the net present value of premium payments we expect to receive from our investees. Our liability for these
guarantees was $4 million as of December 31, 2020, with a corresponding receivable from our investees. Each of Equatorial
Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as
recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.
Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs,
have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri
River. As a result, as of December 31, 2020, we have a $107 million current liability in suspended royalty and working interest
revenue, including interest, and have a long-term receivable of $23 million for capital and expenses.
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 this enforcement actions would have a material adverse effect
on our consolidated financial position, results of operations or cash flow.
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. Certain of these matters are
discussed below.
Environmental matters – We have incurred and will continue to incur capital, operating and maintenance and remediation
expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset
by the prices we receive for our products and services, our operating results will be adversely affected. We believe that
substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact
on each competitor may vary depending on a number of factors, including the age and location of its operating facilities,
marketing areas and production processes. These laws generally provide for control of pollutants released into the environment
and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for
noncompliance.
At December 31, 2020 and 2019, accrued liabilities for remediation were not material. It is not presently possible to
estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.
Guarantees – Over the years, we have sold various assets in the normal course of our business. Certain of the related
agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations,
warranties, covenants and agreements and environmental and general indemnifications that require us to perform upon the
occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling
assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such
101
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the
guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying
triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
Contract commitments – At December 31, 2020 and 2019, contractual commitments to acquire property, plant and
equipment totaled $15 million and $41 million.
In connection with the sale of our operated producing properties in the greater Ewing Bank area and non-operated
producing interests in the Petronius and Neptune fields in the Gulf of Mexico, we retained an overriding royalty interest in the
properties. As part of the sale agreement, cumulative proceeds associated with the production of our override were $57 million
as of December 31, 2020, and are dedicated solely to the satisfaction of the corresponding future abandonment obligations of
the properties. The term of our override ends once sales proceeds equal $70 million.
102
Select Quarterly Financial Data (Unaudited)
2020
2019
(In millions,
except per share data)
Revenues from contracts with
customers
Income (loss) before income
taxes (a)(b)
1st Qtr.
2nd Qtr. 3rd Qtr.
4th Qtr.
1st Qtr.
2nd Qtr. 3rd Qtr.
4th Qtr.
$ 1,024 $
490 $
761 $
822
$ 1,200 $ 1,381 $ 1,249 $ 1,233
(49)
(765)
(310)
(341)
27
193
175
(3)
Net income (loss)
$
(46) $
(750) $
(317) $
(338) $
174 $
161 $
165 $
(20)
Income (loss) per basic and
diluted share:
Net income (loss)
$
(0.06) $
(0.95) $
(0.40) $
(0.43) $
0.21 $
0.20 $
0.21 $
(0.03)
Dividends paid per share
(a) The first quarter of 2020, includes mark-to-market gain on commodity derivatives of $171 million and a full impairment of goodwill in our International
0.05 $ — $ — $
0.05 $
0.05 $
0.05 $
0.03
0.05
$
$
reporting unit of $95 million. (See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements).
Additionally, the second and third quarters of 2020 include impairments on an equity method investment of $152 million and $18 million, respectively.
The fourth quarter of 2020 also includes $46 million of proved property impairments and $78 million of unproved property impairments. (For more
information on impairments, see Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements).
(b)
The first and fourth quarter of 2019 includes a mark-to-market loss on commodity derivatives of $113 million and $55 million.
103
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
The supplementary information is disclosed by the following geographic areas: the U.S.; E.G.; Libya; and Other
International (“Other Int’l”), which includes the U.K. and the Kurdistan Region of Iraq. For further details on our dispositions
that affect the information included in this supplemental information, see Note 5.
Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGLs,
and natural gas reserve estimates are reviewed and approved by our Corporate Reserves Group (“CRG”), which includes our
Vice President of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGLs and natural gas
reserve estimates are developed or reviewed by Qualified Reserves Estimators (“QREs”). QREs are petro-technical
professionals located throughout our organization who meet the qualifications we have established for employees engaged in
estimating reserves and resources. QREs have the education, experience and training necessary to estimate reserves and
resources in a manner consistent with all external reserve estimation regulations and internal resource estimation directives and
practices. QREs generally hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of five
years of industry experience with at least three years in reserve estimation and have completed our QRE training course. All
reserves changes (including proved) must be approved by our Asset leadership and CRG. Additionally, any change to proved
reserve estimates in excess of 5 mmboe on a total field basis, within a single month, must be approved by the Vice President of
Corporate Reserves.
The Vice President of Corporate Reserves, who reports to our Executive Vice President and Chief Financial Officer, has a
Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in Texas and Colorado. In his 22
years with Marathon Oil, he has held numerous engineering and management positions related to the Company’s U.S.
production operations in Oklahoma, Colorado and North Dakota, as well as international production operations in Aberdeen
and Kurdistan. Prior positions include Vice President of petro-technical support teams (Technology Application) and Regional
Vice President of the Bakken Asset. He is a 25 year member of the Society of Petroleum Engineers (“SPE”).
Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve
analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The
observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the
reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for
booking proved reserves.
Audits of Estimates
We have established a robust series of internal controls, policies and processes intended to ensure the quality and accuracy
of our internal reserve estimates. We also engage third-party consultants to audit our estimates of proved reserves. Our policy
requires that audits are provided that comprise at least 80% of our total proved reserves over a rolling four-year period, adjusted
for dispositions. We have conducted our audits on a one-year in arrears basis and accordingly, our third-party consultants have
not yet performed any audits of our reserve estimates for the year-ended December 31, 2020. In calculating our proved reserve
audit coverage percentage, we only include the most recent year a field was audited within the rolling four-year period. To
illustrate, our third-party proved reserve audit conducted during 2020 was for reserve estimates as of December 31, 2019 and
covered reserves in Equatorial Guinea (169 mmboe). The reserve audits conducted during 2019 were for reserve estimates as of
December 31, 2018 and included reserves in Eagle Ford (347 mmboe) and Oklahoma (255 mmboe), which is reflected net of
2019 production in calculating our audit coverage as of December 31, 2020. The reserve audits conducted during 2018 were for
reserve estimates as of December 31, 2017 and included reserves in Bakken (283 mmboe), which is reflected net of 2018 and
2019 production in calculating our audit coverage as of December 31, 2020. On this basis, our third-party reserve audits
covered 88% of our total proved reserves, excluding dispositions. An audit tolerance at a field level of +/- 10% to our internal
estimates has been established. All audits conducted during this period fell within the established tolerance.
For the reserve estimates as of December 31, 2019, Netherland, Sewell & Associates, Inc. (“NSAI”) prepared a reserves
certification for the Alba field in E.G. The NSAI summary report is filed as an exhibit to this Annual Report on Form 10-K.
Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas
companies before joining NSAI. NSAI’s technical team members meet or exceed the education, training and experience
requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the SPE. The senior technical advisor has over 16 years of practical experience in petroleum engineering and
the estimation and evaluation of reserves and is a registered Professional Engineer in the State of Texas. The second team
member has over 14 years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the
State of Texas.
104
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Ryder Scott Company performed audits for reserve estimates of our fields as of December 31, 2018 and 2017. Their
summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 38 years of
industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a 25 year
member of SPE and is a registered Professional Engineer in the State of Texas.
Estimated Quantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of crude oil and condensate, NGLs and natural gas is a highly technical
process which is based upon several underlying assumptions that are subject to change. Proved reserves are determined using
“SEC Pricing”, calculated as an unweighted arithmetic average of the first-day-of-the-month closing price for each month. As
discussed in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Critical Accounting Estimates, commodity prices are volatile which can have an impact on proved
reserves. If 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. It is difficult to
estimate the magnitude of any potential price change and the effect on proved reserves, due to numerous factors (including
future crude oil price and performance revisions).
The table below provides the 2020 SEC pricing for certain benchmark prices:
WTI crude oil (per bbl)
Henry Hub natural gas (per mmbtu)
Brent crude oil (per bbl)
Mont Belvieu NGLs (per bbl)
2020 SEC Pricing
$
$
$
$
39.57
1.99
41.77
14.41
105
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
(mmbbl)
Crude oil and condensate
Proved developed and undeveloped reserves:
Beginning of year - 2018
Revisions of previous estimates
Extensions, discoveries and other additions
Production
Sales of reserves in place
End of year - 2018
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and other additions
Production
Sales of reserves in place
End of year - 2019
Revisions of previous estimates
Extensions, discoveries and other additions
Production
Sales of reserves in place
End of year - 2020
Proved developed reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
Proved undeveloped reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
U.S.
E.G.(a)
Libya(b)
Other
Int'l(c)
Total
570
49
42
(63)
(3)
595
34
9
53
(69)
(3)
619
(86)
16
(65)
(1)
483
263
287
304
301
307
308
315
182
39
3
—
(6)
—
36
3
—
—
(6)
—
33
(2)
—
(5)
—
26
39
36
30
23
—
—
3
3
165
—
—
(3)
(162)
—
—
—
—
—
—
—
—
—
—
—
—
165
—
—
—
—
—
—
—
26
3
2
(5)
(1)
25
—
—
—
(2)
(23)
—
—
—
—
—
—
17
22
—
—
9
3
—
—
800
55
44
(77)
(166)
656
37
9
53
(77)
(26)
652
(88)
16
(70)
(1)
509
484
345
334
324
316
311
318
185
106
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(mmbbl)
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of year - 2018
Revisions of previous estimates
Extensions, discoveries and other additions
Production
Sales of reserves in place
End of year - 2018
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and other additions
Production
Sales of reserves in place
End of year - 2019
Revisions of previous estimates
Extensions, discoveries and other additions
Production
End of year - 2020
Proved developed reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
Proved undeveloped reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
U.S.
E.G.(a)
Libya(b)
Other
Int'l(c)
Total
229
(9)
25
(20)
(1)
224
(21)
5
19
(22)
(1)
204
(33)
6
(22)
155
118
119
122
110
111
105
82
45
25
1
—
(4)
—
22
2
—
—
(3)
—
21
(2)
—
(3)
16
25
22
19
14
—
—
2
2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
254
(8)
25
(24)
(1)
246
(19)
5
19
(25)
(1)
225
(35)
6
(25)
171
143
141
141
124
111
105
84
47
107
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(bcf)
Natural gas
Proved developed and undeveloped reserves:
Beginning of year - 2018
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and other additions
Production(d)
Sales of reserves in place
End of year - 2018
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and other additions
Production(d)
Sales of reserves in place
End of year - 2019
Revisions of previous estimates
Extensions, discoveries and other additions
Production(d)
Sales of reserves in place
End of year - 2020
Proved developed reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
Proved undeveloped reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
U.S.
E.G.(a)
Libya(b)
Other
Int'l(c)
Total
1,324
188
—
198
833
35
—
—
(156)
(153)
(1)
1,553
(223)
28
118
(160)
(38)
1,278
7
45
—
715
108
—
—
(133)
—
690
5
—
(155)
(121)
(1)
1,174
726
869
825
827
598
684
453
347
—
574
833
715
649
526
—
—
41
48
204
—
—
—
(1)
(203)
—
—
—
—
—
—
—
—
—
—
—
—
94
—
—
—
110
—
—
—
8
4
—
—
(5)
—
7
—
—
—
(3)
(4)
—
—
—
—
—
—
2
7
—
—
6
—
—
—
2,369
227
—
198
(315)
(204)
2,275
(115)
28
118
(296)
(42)
1,968
12
45
(276)
(1)
1,748
1,655
1,591
1,474
1,353
714
684
494
395
108
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(mmboe)
Total Proved Reserves
Proved developed and undeveloped reserves:
Beginning of year - 2018
Revisions of previous estimates
Extensions, discoveries and
other additions
Production(d)
Sales of reserves in place
End of year - 2018
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and
other additions
Production(d)
Sales of reserves in place
End of year - 2019
Revisions of previous estimates
Extensions, discoveries and
other additions
Production(d)
Sales of reserves in place
End of year - 2020
Proved developed reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
Proved undeveloped reserves:
Beginning of year - 2018
End of year - 2018
End of year - 2019
End of year - 2020
U.S.
E.G.(a)
Libya(b)
Other
Int'l(c)
Total
1,020
71
100
203
8
—
(109)
(35)
(4)
1,078
(23)
18
91
—
176
24
—
—
(117)
(11)
1,036
(31)
—
169
(118)
(4)
30
—
(112)
(28)
(1)
835
502
552
563
549
518
526
473
286
—
137
203
176
158
125
—
—
11
12
199
—
—
(3)
(196)
—
—
—
—
—
—
—
—
—
—
—
—
181
—
—
—
18
—
—
—
27
5
2
(6)
(1)
27
—
—
—
(3)
(24)
—
—
—
—
—
—
17
24
—
—
10
3
—
—
1,449
84
102
(153)
(201)
1,281
1
18
91
(151)
(35)
1,205
(122)
30
(140)
(1)
972
903
752
721
674
546
529
484
298
(a)
(b)
(c)
(d)
Consists of estimated reserves from properties governed by production sharing contracts.
In 2018, we closed on the sale of our subsidiary, Marathon Oil Libya Limited.
In 2019, we closed on the sale of our U.K. business and our non-operated interested in the Atrush block of Kurdistan. These volumes are reflected in
Other Int’l in the tables above for the periods presented.
Excludes the resale of purchased natural gas used in reservoir management.
109
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
2020 proved reserves decreased by 233 mmboe primarily due to the following:
•
•
•
•
46 mmboe associated with technical revisions, including lower operating costs
130 mmboe due to decreased capital activity in the forecasted 5-year plan in the U.S. resource plays
38 mmboe due to reduced commodity prices
Revisions of previous estimates: Decreased by 122 mmboe as referenced below:
Increases:
•
Decreases:
•
•
Extensions, discoveries and other additions: Increased by 30 mmboe in the U.S. resource plays as referenced below:
Increases:
•
•
Production: Decreased by 140 mmboe.
18 mmboe associated with wells to sales from unproved categories
12 mmboe associated with the expansion of proved areas
Sales of reserves in place: Decreased by 1 mmboe due to divestitures of certain U.S. assets.
2019 proved reserves decreased by 76 mmboe primarily due to the following:
•
•
•
•
•
20 mmboe associated with wells to sales that were additions to the plan
11 mmboe associated with planned compression in E.G.
11 mmboe due to technical revisions in E.G.
Revisions of previous estimates: Increased by 1 mmboe as referenced below:
Increases:
•
•
•
Decreases:
•
•
•
24 mmboe due to reduced commodity pricing
12 mmboe due to technical revisions in the U.S. resource plays
5 mmboe due to changes in the 5-year plan in the U.S. resource plays
Purchases of reserves in place: Increased by 18 mmboe due to the acquisition in the Eagle Ford.
Extensions, discoveries and other additions: Increased by 91 mmboe in the U.S. resource plays as referenced below:
Increases:
•
•
Production: Decreased by 151 mmboe.
53 mmboe associated with the expansion of proved areas
38 mmboe associated with wells to sales from unproved categories
Sales of reserves in place: Decreased by 35 mmboe as referenced below:
Decreases:
•
•
•
19 mmboe associated with the sale of assets in the U.K.
11 mmboe associated with divestitures of certain U.S. assets
5 mmboe associated with the sale of the Atrush block in Kurdistan
2018 proved reserves decreased by 168 mmboe primarily due to the following:
•
•
•
•
Revisions of previous estimates: Increased by 84 mmboe as referenced below:
Increases:
•
108 mmboe associated with the acceleration of higher economic wells in the U.S. resource plays into the 5-
year plan
15 mmboe associated with wells to sales that were additions to the plan
•
Decreases:
•
39 mmboe due to technical revisions across the business
Extensions, discoveries and other additions: Increased by 102 mmboe primarily in the U.S. resource plays as
referenced below:
Increases:
•
•
69 mmboe associated with the expansion of proved areas
33 mmboe associated with wells to sales from unproved categories
Production: Decreased by 153 mmboe.
Sales of reserves in place: Decreased by 201 mmboe as referenced below:
110
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Decreases:
•
•
•
196 mmboe associated with the sale of our subsidiary in Libya
4 mmboe associated with divestitures of certain conventional assets in New Mexico and Michigan
1 mmboe associated with the sale of the Sarsang block in Kurdistan
Changes in Proved Undeveloped Reserves
The following table shows changes in proved undeveloped reserves for 2020:
(mmboe)
Beginning of year
Revisions of previous estimates
Extensions, discoveries and other additions
Transfers to proved developed
End of year
484
(127)
11
(70)
298
Revisions of prior estimates: Decreased by 127 mmboe as referenced below:
Increases:
•
Decreases:
19 mmboe associated with technical revisions
•
•
133 mmboe due to reduction of capital activity in the forecasted 5-year plan in the U.S. resource plays
13 mmboe due to reduced commodity pricing
Extensions, discoveries and other additions: Increased by 11 mmboe associated with expansion of proved areas in Northern
Delaware.
Transfers to proved developed: 70 mmboe of PUD reserves were converted to proved developed status during 2020, primarily
from assets in our U.S. resource plays. This 2020 transfer equates to a 14% PUD conversion rate and a 5-year average annual
PUD conversion rate during the 2016-2020 period of 18%. All proved undeveloped reserve drilling locations are scheduled to
be producing within five years of the initial booking date.
Costs Incurred & Future Costs to Develop
Costs incurred in 2020, 2019 and 2018 relating to the development of proved undeveloped reserves were $466 million,
$1,261 million and $1,082 million.
The following table shows future development costs estimated to be required for the development of proved undeveloped
reserves for future years.
(In millions)
2021
2022
2023
2024
2025
Future Development
Costs
$
808
874
822
577
286
111
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization
(In millions)
Year Ended December 31, 2020
Capitalized Costs:
Proved properties
Unproved properties
Total
Accumulated depreciation, depletion and amortization:
Proved properties
Unproved properties(a)
Total
Net capitalized costs
Year Ended December 31, 2019
Capitalized Costs:
Proved properties
Unproved properties
Total
Accumulated depreciation, depletion and amortization:
Proved properties
Unproved properties(a)
Total
Net capitalized costs
(a)
Includes unproved property impairments (See Note 12).
U.S.
E.G.
Total
$
30,398 $
2,057 $
2,721
33,119
17,616
433
18,049
—
2,057
1,650
(7)
1,643
$
15,070 $
414 $
$
29,250 $
2,042 $
2,880
32,130
15,435
357
15,792
12
2,054
1,568
(7)
1,561
$
16,338 $
493 $
32,455
2,721
35,176
19,266
426
19,692
15,484
31,292
2,892
34,184
17,003
350
17,353
16,831
112
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Costs Incurred for Property Acquisition, Exploration and Development (a)
(In millions)
December 31, 2020
Unproved property acquisition
Exploration
Development
Total
December 31, 2019
Property acquisition:
Proved
Unproved
Exploration
Development
Total
December 31, 2018
Property acquisition:
Proved
Unproved
Exploration
Development
Total
U.S.
E.G.
Other Int’l
Total
$
$
$
$
$
$
$
36
330
780
1,146
$
93
282
862
1,675
2,912
211
144
929
1,332
2,616
$
$
$
$
—
—
9
9
—
—
—
1
1
—
—
1
(2)
(1)
$
$
$
$
$
$
—
—
—
—
—
—
—
23
23
11
—
(9)
(126) (b)
(124)
$
$
$
$
$
$
36
330
789
1,155
93
282
862
1,699
2,936
222
144
921
1,204
2,491
(a)
(b)
Includes costs incurred whether capitalized or expensed.
Includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities.
113
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
Year Ended December 31, 2020
Revenues and other income:
Sales
Other income(a)
Total revenues and other income
Expenses:
Production costs
Exploration expenses(b)
Depreciation, depletion and amortization(c)
Technical support and other
Total expenses
Results before income taxes
Income tax (provision) benefit
Results of operations
Year Ended December 31, 2019
Revenues and other income:
Sales
Other income(a)
Total revenues and other income
Expenses:
Production costs
Exploration expenses(b)
Depreciation, depletion and amortization(c)
Technical support and other
Total expenses
Results before income taxes
Income tax (provision) benefit
Results of operations
Results of operations
Year Ended December 31, 2018
Revenues and other income:
Sales
Other income(a)
Total revenues and other income
Expenses:
Production costs
Exploration expenses(b)
Depreciation, depletion and amortization(c)
Technical support and other
Total expenses
Results before income taxes
Income tax (provision) benefit
Results of operations
Results of operations
(a)
U.S.
E.G.
Libya
Other
Int’l
Total
$
2,955 $
9
2,964
(1,134)
(175)
(2,260)
(48)
(3,617)
(653)
9
(644) $
4,472 $
46
4,518
(1,384)
(149)
(2,274)
(38)
(3,845)
673
(6)
667 $
4,842 $
81
4,923
(1,371)
(245)
(2,247)
(49)
(3,912)
1,011
19
1,030 $
$
$
$
$
$
173 $
—
173
(61)
(6)
(81)
(3)
(151)
22
(5)
17 $
307 $
—
307
(73)
—
(97)
(9)
(179)
128
(32)
96 $
383 $
—
383
(68)
(51)
(117)
(5)
(241)
142
(38)
104 $
— $
—
—
—
—
—
—
—
—
—
— $
— $
—
—
—
—
—
—
—
—
—
— $
196 $
255
451
(12)
—
(8)
—
(20)
431
(163)
268 $
— $
—
—
—
—
—
—
—
—
—
— $
3,128
9
3,137
(1,195)
(181)
(2,341)
(51)
(3,768)
(631)
4
(627)
140 $
3
143
4,919
49
4,968
(71)
—
(23)
(10)
(104)
39
12
51 $
(1,528)
(149)
(2,394)
(57)
(4,128)
840
(26)
814
402 $
104
506
5,823
440
6,263
(180)
7
(102)
(6)
(281)
225
(124)
101 $
(1,631)
(289)
(2,474)
(60)
(4,454)
1,809
(306)
1,503
114
Includes net gain (loss) on dispositions (See Note 5). In 2018 this also includes revisions to asset retirement costs primarily due to changes in U.K.
estimated costs as well as timing of abandonment activities.
Includes exploratory dry well costs, unproved property impairments and other.
Includes long-lived asset impairments (See Note 12).
(b)
(c)
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
The following reconciles results of operations for oil and gas producing activities to segment income (loss):
(In millions)
Results of operations
Year Ended December 31,
2020
2019
2018
$
(627) $
814 $
1,503
Items not included in results of oil and gas operations, net of tax:
Marketing income and other non-oil and gas producing related activities
(135)
(141)
Income from equity method investments
Items not allocated to segment income, net of tax:
Loss (gain) on asset dispositions and other
Long-lived asset impairments
Unproved property impairments
Unrealized loss (gain) on derivatives
Segment income (loss)
19
62
49
82
27
87
—
24
—
124
(170)
214
(304)
103
—
(265)
$
(523) $
908 $
1,081
115
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
U.S. GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein
relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and
an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month
as well as current costs applicable at the date of the estimate. These and other required assumptions have not always proved
accurate in the past, and other valid assumptions would give rise to substantially different results. In addition, the 10% discount
rate required to be used is not necessarily the most appropriate discount factor based on our cost of capital and the risks
associated with our business and the oil and natural gas industry in general. This information is not the fair value nor does it
represent the expected present value of future cash flows of our crude oil and condensate, natural gas liquids and natural gas
reserves.
(In millions)
Year Ended December 31, 2020
Future cash inflows
Future production and support costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for timing of cash flows
Standardized measure of discounted future net cash flows
Year Ended December 31, 2019
Future cash inflows
Future production and support costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for timing of cash flows
Standardized measure of discounted future net cash flows
Year Ended December 31, 2018
Future cash inflows
Future production and support costs
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for timing of cash flows
Standardized measure of discounted future net cash flows
U.S.
E.G.
Other Int’l
Total
$
21,847 $
941 $
(10,822)
(3,977)
(12)
(592)
(19)
(84)
$
$
7,036 $
246 $
(3,207)
(56)
3,829 $
190 $
$
40,487 $
1,812 $
(14,167)
(7,561)
(1,085)
(838)
(18)
(280)
$
17,674 $
676 $
(7,416)
(179)
$
10,258 $
497 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$
22,788
(11,414)
(3,996)
(96)
7,282
(3,263)
4,019
$
$
$
42,299
(15,005)
(7,579)
(1,365)
$
18,350
(7,595)
$
10,755
$
49,054 $
2,218 $
1,813
$
53,085
(15,995)
(7,729)
(1,967)
(878)
(12)
(355)
$
23,363 $
973 $
(10,653)
(254)
$
12,710 $
719 $
(876)
(1,072)
275
140
100
240
(17,749)
(8,813)
(2,047)
(a) $
24,476
(10,807)
$
13,669
(a)
Future cash flows for Other Int’l reflects the impact of future abandonment costs related to the U.K.
116
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Changes in the Standardized Measure of Discounted Future Net Cash Flows
(In millions)
Sales and transfers of oil and gas produced, net of production and support costs
Year Ended December 31,
2020
2019
2018
$ (1,889)
$ (3,345)
$ (4,135)
Net changes in prices and production and support costs related to future production
(7,986)
(3,569)
Extensions, discoveries and improved recovery, less related costs
Development costs incurred during the period
Changes in estimated future development costs
Revisions of previous quantity estimates(a)
Net changes in purchases and sales of minerals in place
Accretion of discount
Net change in income taxes
Net change for the year
Beginning of the year
End of the year
(a)
230
801
718
1,727
2,693
(4,937)
278
7
6,342
998
1,240
(330)
(501)
(9)
(200)
(3,035)
3,921
1,315
440
155
(6,736)
(2,914)
1,175
4,052
5,806
10,755
$ 4,019
13,669
$ 10,755
7,863
$ 13,669
Includes amounts resulting from changes in the timing of production. The year ended 2020 also includes the impact of lower forecasted capital activity in
the 5-year plan in our U.S. resource plays.
117
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period
covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the
design and operation of these disclosure controls and procedures were effective as of December 31, 2020.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” under Item 8 of this Form 10-K.
Attestation Report of the Registered Public Accounting Firm
See “Report of Independent Registered Public Accounting Firm” under Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 2020, there were no changes in our internal control over financial reporting that have
materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
118
Item 10. Directors, Executive Officers and Corporate Governance
PART III
Information required by this item is incorporated by reference to “Proposal 1: Election of Directors,” “Corporate
Governance—Committees of the Board” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy
Statement for the 2021 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 2020 (the
“2021 Proxy Statement”).
See “Executive Officers of the Registrant” under Item 1 of this Form 10-K for information about our executive officers.
Our Code of Ethics for Senior Financial Officers, which applies to the Company’s principal executive officer, principal
financial officer, principal accounting officer or controller, or persons performing similar functions, is available on our website
at www.marathonoil.com under Investors—Corporate Governance. You may request a printed copy free of charge by sending a
request to the Corporate Secretary. We intend to disclose any amendments and any waivers to our Code of Ethics for Senior
Financial Officers on our website at www.marathonoil.com under Investors —Corporate Governance within four business days.
The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.
Item 11. Executive Compensation
Information required by this item is incorporated by reference to “Corporate Governance—Compensation Committee
Interlocks and Insider Participation,” “Compensation Committee Report,” “Director Compensation,” “Compensation
Discussion and Analysis” and “Executive Compensation” in the 2021 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Portions of information required by this item are incorporated by reference to “Security Ownership of Certain Beneficial
Owners and Management” in the 2021 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2020 with respect to shares of Marathon Oil common stock
that may be issued under our existing equity compensation plans:
• Marathon Oil Corporation 2019 Incentive Compensation Plan (the “2019 Plan”)
• Marathon Oil Corporation 2016 Incentive Compensation Plan (the “2016 Plan”) – No additional awards will be granted
under this plan.
• Marathon Oil Corporation 2012 Incentive Compensation Plan (the “2012 Plan”) – No additional awards will be granted
under this plan.
• Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) – No additional awards will be granted
under this plan.
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities
remaining available for
future issuance under
equity compensation plans
Plan category
Equity compensation plans approved
by stockholders
(a)
25,955,630 (a)
Reflects the shares available for issuance under the 2019 Plan for awards of restricted stocks, restricted stock units, stock-based performance units, stock
options and stock appreciation rights.
7,476,429
21.00
$
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item is incorporated by reference to “Transactions with Related Persons,” and “Proposal 1:
Election of Directors—Director Independence” in the 2021 Proxy Statement.
Item 14. Principal Accountant Fees and Services
Information required by this item is incorporated by reference to “Proposal 2: Ratification of Independent Auditor for
2021“ in the 2021 Proxy Statement.
119
Item 15. Exhibits, Financial Statement Schedules
A. Documents Filed as Part of the Report
PART IV
1. Financial Statements – See Part II, Item 8. of this Annual Report on Form 10-K.
2. Financial Statement Schedules – The unaudited financial statements and related footnotes of Alba Plant LLC, our equity
method investment, are being filed within Exhibit 99.9 in accordance with Rule 3-09 of Regulation S-X. All other
financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted
because they are not applicable or the required information is contained in the consolidated financial statements or notes
thereto.
3. Exhibits – The information required by this Item 15 is incorporated by reference to the Exhibit Index accompanying this
Annual Report on Form 10-K.
Item 16. Form 10-K Summary
None.
120
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
February 23, 2021
MARATHON OIL CORPORATION
SIGNATURES
By: /s/ GARY E. WILSON
Gary E. Wilson
Vice President, Controller and Chief Accounting Officer
POWER OF ATTORNEY
Each person whose signature appears below appoints Lee M. Tillman, Dane E. Whitehead, and Gary E. Wilson, and each
of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or
her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on
Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and
Exchange Commission, with full power and authority to each of said attorneys-in-fact and agents to do and perform each and
every act whatsoever that is necessary, appropriate or advisable in connection with any or all of the above-described matters
and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-
in-fact and agents or any of them or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on February 23, 2021 on behalf of the registrant and in the capacities indicated.
Signature
/s/ LEE M. TILLMAN
Lee M. Tillman
/s/ DANE E. WHITEHEAD
Dane E. Whitehead
/s/ GARY E. WILSON
Gary E. Wilson
/s/ GREGORY H. BOYCE
Gregory H. Boyce
/s/ CHADWICK C. DEATON
Chadwick C. Deaton
/s/ MARCELA E. DONADIO
Marcela E. Donadio
/s/ JASON B. FEW
Jason B. Few
/s/ DOUGLAS L. FOSHEE
Douglas L. Foshee
/s/ BRENT J. SMOLIK
Brent J. Smolik
/s/ M.ELISE HYLAND
M. Elise Hyland
/s/ J.KENT WELLS
J. Kent Wells
Title
Chairman, President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Vice President, Controller and Chief Accounting Officer
Director
Director
Director
Director
Director
Director
Director
Director
121
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
Filing Date
Form
10-K
1.1
2/22/2018
10-Q
10.1
5/5/2017
8-K
10-Q
10-K
3.1
3.2
3.3
6/1/2018
8/4/2016
2/28/2014
10-K
4.2
2/28/2014
8-K
4.1
6/2/2014
10-Q
10.1
5/7/2015
8-K
99.1
3/8/2016
Exhibit
Number
1
1.1
2
2.1
3
3.1
3.2
3.3
4
4.1
4.2*
10
10.1
10.2
10.3
Exhibit Index
Exhibit Description
Underwriting Agreement
Bond Purchase Agreement, dated as of November 28, 2017,
between Marathon Oil Corporation, the Parish of St. John the
Baptist, State of Louisiana, and Morgan Stanley & Co. LLC.
Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Share Purchase Agreement, dated as of March 8, 2017, by
and among Marathon Oil Dutch Holdings B.V., as Seller, and
10084751 Canada Limited, as a Buyer and Canadian Natural
Resources Limited, as a Buyer, in respect of Marathon Oil
Canada Corporation.
Articles of Incorporation and By-laws
Restated Certificate of Incorporation of Marathon Oil
Corporation
Marathon Oil Corporation By-laws (Amended and restated
as of February 24, 2016)
Specimen of Common Stock Certificate
Instruments Defining the Rights of Security Holders,
Including Indentures
Indenture, dated as of February 26, 2002, between Marathon
Oil Corporation and The Bank of New York Trust Company,
N.A., successor in interest to JPMorgan Chase Bank as Trustee,
relating to senior debt securities of Marathon Oil Corporation.
Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to
long-term debt issues have been omitted where the amount of
securities authorized under such instruments does not exceed
10% of the total consolidated assets of Marathon Oil. Marathon
Oil hereby agrees to furnish a copy of any such instrument to the
Securities and Exchange Commission upon its request
Description of Registrants Securities
Material Contracts
Amended and Restated Credit Agreement, dated as of May 28,
2014, among Marathon Oil Corporation, as borrower, The
Royal Bank of Scotland plc, as syndication agent, Citibank,
N.A., Morgan Stanley Senior Funding, Inc. and The Bank of
Nova Scotia, as documentation agents, JPMorgan Chase Bank,
N.A., as administrative agent, and certain other financial
institutions named therein
First Amendment, dated as of May 5, 2015, to the Amended
and Restated Credit Agreement dated as of May 28, 2014, by
and among Marathon Oil Corporation, as borrower, JPMorgan
Chase Bank, N.A., as administrative agent, and certain other
financial institutions named therein
Incremental Commitments Supplement, dated as of March 4,
2016, to the Amended and Restated Credit Agreement dated as
of May 28, 2014, as amended by the First Amendment dated as
of May 5, 2015, among Marathon Oil Corporation, as
borrower, the lenders party thereto, The Royal Bank of
Scotland Plc, as syndication agent, Citibank, N.A., Morgan
Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as
documentation agents, and JPMorgan Chase Bank, N.A., as
administrative agent.
1
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
99.1
Filing Date
6/23/2017
Form
8-K
10-Q
10.2
8/3/2017
8-K
99.1
10/22/2018
8-K
10.1
9/24/2019
8-K
10.1
12/8/2020
Exhibit
Number
10.4
10.5
10.6
10.7
10.8
Exhibit Description
Second Amendment, dated as of June 22, 2017, to the
Amended and Restated Credit Agreement dated as of May 28,
2014, as amended by the First Amendment dated as of May 5,
2015, and supplemented by the Incremental Commitments
Supplement dated as of March 4, 2016, among Marathon Oil
Corporation, as borrower, the lenders party thereto, The Royal
Bank of Scotland Plc, as syndication agent, Citibank, N.A.,
Morgan Stanley Senior Funding, Inc. and The Bank of Nova
Scotia, as documentation agents, and JPMorgan Chase Bank,
N.A., as administrative agent.
Incremental Commitment Supplement, dated as of July 11,
2017, to the Amended and Restated Credit Agreement dated as
of May 28, 2014, as amended by the First Amendment dated as
of May 5, 2015, supplemented by the Incremental
Commitments Supplement dated as of March 4, 2016, and
amended by the Second Amendment dated as of June 22, 2017,
among Marathon Oil Corporation, as borrower, the lenders
party thereto, The Royal Bank of Scotland Plc, as syndication
agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and
The Bank of Nova Scotia, as documentation agents, and
JPMorgan Chase Bank, N.A., as administrative agent.
Third Amendment, dated as of October 18, 2018, to the
Amended and Restated Credit Agreement dated as of May 28,
2014, as amended by the First Amendment dated as of May 5,
2015 and the Second Amendment dated as of June 22, 2017 and
as supplemented by the Incremental Commitments Supplement
dated as of March 4, 2016 and Incremental Commitments
Supplement dated as July 11, 2017, among Marathon Oil
Corporation, as borrower, the lenders party thereto, Mizuho
Bank, Ltd, as syndication agent, Citibank, N.A., Morgan
Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as
documentation agents, and JPMorgan Chase Bank, N.A., as
administrative agent
Fourth Amendment, dated as of September 24, 2019, to the
Amended and Restated Credit Agreement dated as of May 28,
2014, as amended by the First Amendment dated as of May 5,
2015, the Second Amendment dated as of June 22, 2017, and
the Third Amendment dated as of October 18, 2018 and as
supplemented by the Incremental Commitments Supplement
dated as of March 4, 2016 and Incremental Commitments
Supplement dated as July 11, 2017, among Marathon Oil
Corporation, as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, and certain other financial institutions
named therein
Fifth Amendment, dated as of December 4, 2020, to the
Amended and Restated Credit Agreement dated as of May 28,
2014, as amended by the First Amendment, dated as of May
5, 2015, the Second Amendment, dated as of June 22, 2017,
the Third Amendment, dated as of October 18, 2018, and the
Fourth Amendment, dated as of September 24, 2019 and as
supplemented by the Incremental Commitments Supplement,
dated as of March 4, 2016 and Incremental Commitments
Supplement, dated as July 11, 2017, among Marathon Oil
Corporation, as borrower, JPMorgan Chase Bank, N.A., as
administrative agent, and certain other financial institutions
named therein
10.9†*
2021 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Non-Employee Directors
2
Exhibit
Number
10.10†
10.11†
10.12†
10.13†
10.14†
10.15†*
10.16†
10.17†
10.18†
10.19†
10.20†
10.21†*
10.22†
10.23†
10.24†
10.25†
10.26†
10.27†
10.28†
Exhibit Description
Marathon Oil Corporation 2019 Incentive Compensation Plan
2019 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers
2019 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers
2019 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Section 16 Officers
2019 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Non-Employee Directors
2020 Form of Marathon Oil Corporation 2019 Incentive
Compensation Plan Performance Unit Award Agreement for
Section 16 Officers
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
App. A
Filing Date
4/12/2019
Form
DEF 14A
10-Q
10.1
8/8/2019
10-Q
10.2
8/8/2019
10-Q
10.3
8/8/2019
10-Q
10.4
8/8/2019
10-K
10.13
2/2/2020
Marathon Oil Corporation 2016 Incentive Compensation Plan
DEF 14A
10-Q
App. A
10.1
4/7/2016
5/2/2019
2019 Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers
2019 Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers
2019 Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Section 16 Officers
2019 Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Performance Unit Award Agreement for
Section 16 Officers
Summary Director Compensation Arrangement, effective 2021
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers (3-year cliff vesting)
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers (3-year prorata vesting)
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Non-Employee Directors (3-year cliff vesting)
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Restricted Stock Unit Award Agreement
for Non-Employee Canadian Directors (3-year cliff vesting)
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Performance Unit Award Agreement for
Section 16 Officers
Form of Marathon Oil Corporation 2016 Incentive
Compensation Plan Performance Unit Award Agreement for
Officers
10-Q
10.2
5/2/2019
10-Q
10.3
5/2/2019
10-Q
10.4
5/2/2019
8-K/A
10.1
10/6/2016
10-K
10.6
2/24/2017
10-K
10.7
2/24/2017
10-K
10.8
2/24/2017
10-K
10.9
2/24/2017
10-K
10.12
2/22/2018
10-K
10.13
2/22/2018
10.29†
Marathon Oil Corporation 2012 Incentive Compensation Plan
DEF 14A
App. III
3/8/2012
3
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
10.1
Filing Date
8/1/2014
Form
8-K
10-Q
10-K
10.1
10.5
11/6/2013
2/22/2013
10-K
10.6
2/22/2013
10-K
10-K
10.5
10.6
2/29/2012
2/29/2012
10-K
10.5
2/28/2011
10-K
10.29
2/24/2017
10-K
10-K
10-K
10-K
10.32
2/29/2012
10.31
2/29/2012
10.10
2/28/2011
10.32
2/27/2009
8-K
10.1
5/26/2011
Exhibit
Number
10.30†
10.31†
10.32†
10.33†
10.34†
10.35†
10.36†
10.37†
10.38†
10.39†
10.40†*
10.41†
10.42†
10.43
21.1*
23.1*
23.2*
23.3*
23.4*
31.1*
31.2*
32.1*
32.2*
Exhibit Description
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Non-Qualified Stock Option Award
Agreement
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Initial CEO Option Grant Agreement
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers (3-year prorata vesting)
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Officers (3-year prorata vesting)
Marathon Oil Corporation 2007 Incentive Compensation Plan
Form of Marathon Oil Corporation 2007 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Officers
Form of Marathon Oil Corporation 2007 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers
Marathon Oil Corporation Deferred Compensation Plan for
Non-Employee Directors (Amended and Restated as of
December 20, 2016)
Marathon Oil Company Deferred Compensation Plan Amended
and Restated Effective June 30, 2011
Marathon Oil Company Excess Benefit Plan Amended and
Restated
Marathon Oil Corporation Officer Change in Control Severance
Benefits Plan (As amended effective January 27, 2021)
Marathon Oil Corporation Policy for Repayment of Annual
Cash Bonus Amounts
Marathon Oil Corporation Executive Tax, Estate, and Financial
Planning Program, Amended and Restated, Effective January 1,
2009
Tax Sharing Agreement dated as of May 25, 2011 among
Marathon Oil Corporation, Marathon Petroleum Corporation
and MPC Investment LLC
List of Significant Subsidiaries
Consent of Independent Registered Public Accounting Firm
Consent of Independent Registered Public Accounting Firm
Consent of Ryder Scott Company, L.P., independent petroleum
engineers and geologists
Consent of Netherland, Sewell & Associates, Inc., independent
petroleum engineers and geologists
Certification of President and Chief Executive Officer pursuant
to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange
Act of 1934
Certification of Chief Financial Officer pursuant to Rule
13(a)-14 and 15(d)-14 under the Securities Exchange Act
of 1934
Certification of President and Chief Executive Officer pursuant
to 18 U.S.C. Section 1350
Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350
4
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
Filing Date
Form
10-K
10-K
10-K
99.1
99.2
99.2
2/20/2020
2/20/2020
2/21/2019
Exhibit
Number
99.1*
99.2
99.3
99.4
Exhibit Description
Summary report of audits performed by Netherland, Sewell &
Associates, Inc., independent petroleum engineers and
geologists for 2019
Summary report of audits performed by Ryder Scott Company,
L.P., independent petroleum engineers and geologists for 2018
Summary report of audits performed by Ryder Scott Company,
L.P., independent petroleum engineers and geologists for 2018
Summary report of audits performed by Ryder Scott Company,
L.P., independent petroleum engineers and geologists for 2017
99.9*
Alba Plant, LLC financial statements as of December 31, 2020
101.INS*
XBRL Instance Document - the XBRL Instance Document
does not appear in the Interactive Data File because its XBRL
tags are embedded within the Inline XBRL document
101.SCH* XBRL Taxonomy Extension Schema
101.CAL* XBRL Taxonomy Extension Calculation Linkbase
101.DEF*
XBRL Taxonomy Extension Definition Linkbase
101.LAB* XBRL Taxonomy Extension Label Linkbase
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase
104*
Cover Page Interactive Data File, formatted in iXBRL and
contained in Exhibit 101
*
†
Filed herewith.
Management contract or compensatory plan or arrangement.
5
Corporate Information
Corporate Headquarters
5555 San Felipe Street
Houston, TX 77056-2723
Marathon Oil Corporation Web Site
www.marathonoil.com
Investor Relations Office
5555 San Felipe Street
Houston, TX 77056-2723
Guy Baber, VP Investor Relations
InvestorRelations@marathonoil.com
+1 713-296-1892
Notice of Annual Meeting
The 2021 Annual Meeting of Stockholders will be held online at
www.virtualshareholdermeeting.com/MRO2021 on May 26, 2021,
10:00 a.m. Central Time
Independent Accountants
PricewaterhouseCoopers LLP
1000 Louisiana Street, Suite 5800
Houston, TX 77002-5021
Stock Exchange Listing
New York Stock Exchange
Common Stock Symbol
MRO
Stock Transfer Agent
Computershare
211 Quality Circle, Suite 210
College Station, TX 77845
888-843-5542 (Toll free - U.S., Canada, Puerto Rico)
+1 781-575-4735 (non-U.S.)
web.queries@computershare.com
Stockholder Return Performance Graph
The line graph below compares the yearly change in cumulative
total stockholder return for our common stock with the
cumulative total return of the Standard & Poor’s 500 Stock Index
(“S&P 500”), the Peer Group Index shown in our 2020 Annual
Report (the “2020 Peer Group”), and the Peer Group Index
shown in our 2019 Annual Report (the “2019 Peer Group”). We
use a Peer Group Index because there is no relevant published
industry or line-of-business index that reflects the companies
against which we compete as an independent exploration and
production company. The 2020 Peer Group Index is comprised
of Apache Corporation, Chesapeake Energy Corporation,
Cimarex Energy Co., Concho Resources Inc., Continental
Resources, Inc., Devon Energy Corporation, EOG Resources,
Inc., Hess Corporation, Murphy Oil Corporation, Ovintiv Inc. and
Pioneer Natural Resources Company. In 2020, Noble Energy,
Inc. was removed because of its acquisition and replaced with
Concho Resources Inc.
RIDER C
Comparison of Cumulative Total Return on $100
Invested In Marathon Oil Common Stock on December 31, 2015
vs.
*S&P 500 and Peer Group Index
$250
$200
$150
$100
$50
$0
12/15
12/16
12/17
12/18
12/19
12/20
MRO
S&P 500
2019 Peer Group Index
2020 Peer Group Index
*Total return assumes reinvestment of dividends
Company Information
Board of Directors (as of April 1, 2021)
Executive Officers (as of April 1, 2021)
Lee M. Tillman
Chairman, President and CEO, Marathon Oil Corporation
Lee M. Tillman
Chairman, President and Chief Executive Officer
Dane E. Whitehead
Executive Vice President and Chief Financial Officer
Patrick J. Wagner
Executive Vice President, Corporate Development and Strategy
Mike Henderson
Executive Vice President, Operations
Kimberly O. Warnica
Senior Vice President, General Counsel and Secretary
Gary E. Wilson
Vice President, Controller and Chief Accounting Officer
Gregory H. Boyce
Independent Lead Director
Former Executive Chairman, Peabody Energy Corporation
Chadwick C. Deaton
Former Executive Chairman, Baker Hughes Incorporated
Marcela E. Donadio
Former Partner, Ernst & Young, LLP
Jason B. Few
President, CEO and Chief Commercial Officer, Fuelcell Energy, Inc.
Douglas L. Foshee
Founder and Owner, Sallyport Investments, LLC
Former Chairman, President and CEO, El Paso Corporation
M. Elise Hyland
Former Senior Vice President, EQT Corporation
Holli C. Ladhani
Former President and CEO, Select Energy
Brent J. Smolik
Former President and COO of Noble Energy, Inc.
J. Kent Wells
Former CEO and President, Fidelity Exploration & Production
Company and Vice Chairman of MDU Resources
Forward-Looking Statements and Other Items
This annual report 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: the Company’s future capital program and the allocation
thereof, capital expenditure budget, debt reduction, GHG intensity target, returns and free cash flow.
While the Company believes that its assumptions concerning future events are reasonable, we can give no assurance that these
expectations will 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/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 Equatorial Guinea, including changes in foreign currency
exchange rates, interest rates, inflation rates; 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 the Company’s 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 contractual obligations; unforeseen hazards such as weather
conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the government or military response thereto;
cyber-attacks; changes in safety, health, environmental, tax and other regulations, requirements or initiatives, including initiatives
addressing the impact of global climate change, air emissions, or water management; other geological, operating and economic
considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company’s
2020 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases available at
www.marathonoil.com. Except as required by law, the Company assumes no duty to revise or update any forward-looking
statements whether as a result of new information, future events or otherwise.
The letter in this annual report includes non-GAAP financial measures, including free cash flow. Reconciliations of the differences
between non-GAAP financial measures used in the letter and their most directly comparable GAAP financial measures are available
at www.marathonoil.com in the 4Q20 Investor Packet.