Dear fellow shareholders,
2017 was truly a pivotal year for Marathon Oil, as we solidified high quality, differentiated
positions in the four lowest-cost, highest-margin U.S. oil plays. We made significant progress
across every element of our playbook, and ended the year with a stronger balance sheet,
a lower cost structure, a more concentrated portfolio, and an outstanding track record of
consistent execution across all our assets.
A remarkable 2017 has positioned us well for future success. We’ve transitioned from portfolio
transformation to execution delivery at scale across our U.S. resource plays. Our 2018 capital
allocation philosophy is fully consistent with how we managed the business in 2017, which is
to deliver a returns-focused program that balances cash flow with our CapEx and dividend,
and achieves that at a moderate oil price of $50 WTI while generating meaningful free cash
flow at $60. With over 90 percent of our 2018 development capital allocation associated
with the U.S. resource plays, our margins will naturally expand as a greater percentage of our
production is sourced from these high quality assets.
This margin expansion story, coupled with outstanding financial flexibility, will help drive
improvements in corporate cash returns and cash flow per debt-adjusted share. Our actions
will always be driven by seeking the greatest long-term value for our shareholders, while
remaining steadfast in our core values that include first and foremost being a safe and
responsible operator.
We thank all our dedicated employees and contractors who have made such a difference in
2017, driving execution excellence in every asset, every quarter. Their talent and innovation will
continue to position us favorably to outperform the competition through 2018 and beyond.
Lee M. Tillman
President and Chief Executive Officer
Dennis H. Reilley
Chairman of the Board of Directors
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, 2017
Commission file number 1-5153
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, TX 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
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
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the
preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be
submitted and posted 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 and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
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
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
The aggregate market value of Common Stock held by non-affiliates as of June 30, 2017: $10,050 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 849,755,866 shares of Marathon Oil Corporation Common Stock outstanding as of February 14, 2018.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2018 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
PART I
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4. Mine Safety Disclosures
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Item 6.
Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
PART IV
Item 14.
Principal Accountant Fees and Services
Item 15. Exhibits, Financial Statement Schedules
Item 16.
Form 10-K Summary
SIGNATURES
5
16
25
25
25
25
26
27
28
51
53
115
115
115
116
116
116
117
117
118
118
119
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.
AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta,
Canada, in which we held a 20% non-operated working interest.
bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
bcf – Billion cubic feet.
boe – Barrels of oil equivalent.
btu – British thermal unit, an energy equivalence measure.
Capital Development Program – 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.
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.
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.
EPA – United States Environmental Protection Agency.
E&P – Exploration and production.
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 price – a natural gas benchmark price quoted at settlement date average.
IRS – United States Internal Revenue Service.
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.
Marathon Oil – Marathon Oil Corporation and its consolidated subsidiaries: 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.
mmbbl – Million barrels.
mmboe – Million barrels of oil equivalent.
mmbtu – Million British thermal units.
mmcfd – Million stabilized cubic feet per day.
mmta – Million metric tonnes per annum.
1
MPC – Marathon Petroleum Corporation – the separate independent company, which owns and operates the refining, marketing
and transportation operations.
mt – metric tonnes
mtd – metric tonnes per day.
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.
OECD – Organization for Economic Cooperation and Development.
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 internal losses.
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, natural gas and our historical synthetic crude oil reserves are those
quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil, 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.
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).
STACK – Sooner Trend, Anadarko (basin), Canadian (and) Kingfisher (counties).
TD – Total depth or the bottom of a drilled hole.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
U.K. – United Kingdom.
U.S. – United States of America.
2
U.S. resource plays – Consists of our unconventional properties in the Oklahoma, Eagle Ford, Bakken and Northern Delaware.
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.
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, non-core asset sales, and financial
flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2018 capital
development program 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 jurisdictions in which we operate, including changes in foreign
currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
risks relating to our hedging activities;
capital available for exploration and development;
drilling and operating risks;
• well production timing;
•
•
•
•
•
•
•
•
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, acts of war or terrorist acts and the governmental or military response
thereto;
cyber-attacks;
changes in safety, health, environmental, tax and other regulations;
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 assume no duty to revise or update any forward-looking statements whether 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
Item 1. Business
General
PART I
Marathon Oil Corporation (NYSE: MRO) is an independent exploration and production company based in Houston, Texas,
focused on U.S. unconventional resource plays with operations in the United States, Europe and Africa. 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 and managed based upon geographic location and the nature of
the products and services offered. The two segments are:
•
•
United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United
States;
International E&P – 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.
We were incorporated in 2001.
Our strategy is to deliver competitive returns by focusing on the lowest cost, highest margin U.S. resource plays while
maintaining a peer-leading balance sheet. 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.
We are concentrated on our core operations in our U.S. unconventional resource plays and E.G. The map below shows the
locations of our core operations:
* Our additional locations include the Gulf of Mexico, U.K., Libya, Gabon and the Kurdistan Region of Iraq.
Segment and Geographic Information
In the second quarter of 2017, we closed on the sale of our Canadian business which includes our Oil Sands Mining
segment and exploration stage in-situ leases. The Canadian business is reflected as discontinued operations in all periods
presented. Additionally, we have renamed our North America E&P segment to United States E&P segment, effective June 30,
2017. See Item 8. Financial Statements and Supplementary Data – Note 1 to the consolidated financial statements for further
detail. For reportable operating segment and geographic financial information, see Item 8. Financial Statements and
Supplementary Data – Note 6 to the consolidated financial statements.
In the following discussion regarding our United States E&P and International E&P segments, references to sales or
investment indicate our ownership interest or share, as the context requires.
5
United States E&P Segment
We are engaged in oil and gas exploration, development and production activities in the U.S. Our primary focus in the
United States E&P segment is concentrated within our four high quality unconventional 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 E&P-- Unconventional Resource Plays
Eagle Ford – We have been operating in the South Texas Eagle Ford play since 2011, where roughly two thirds of our
acreage is located in Karnes County and Atascosa County. We operate 32 central gathering and treating facilities across the field
that support more than 1,500 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, Atascosa and Bee Counties.
Bakken – We have been operating in North Dakota and eastern Montana since 2006. The majority of our acreage is in core
prospects within McKenzie, Mountrail, and Dunn Counties in North Dakota. We continue focusing on the high-return
Myrmidon area building on the successes from our enhanced completion designs, as well as delineating our position in Hector.
Oklahoma – Our primary focus in Oklahoma has been delineation and leasehold protection in the Meramec play in the
STACK and delineation of the Woodford and Springer plays in the SCOOP, as we move toward infill development. We hold
net acreage with rights to the Woodford, Springer, Meramec, Osage, Oswego, Granite Wash and other Pennsylvanian and
Mississippian plays, with a majority of this in the SCOOP and STACK.
Northern Delaware – We closed on multiple Permian acquisitions during 2017, with a majority of the acreage in Northern
Delaware. These acquisitions give us a strong foundational footprint in the region where we have begun developing the
Wolfcamp and Bone Spring plays. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated
financial statements for further detail.
Other United States
Our remaining properties in the United States primarily consist of outside operated assets in the Gulf of Mexico, including
the Gunflint field where we hold an 18% non-operated working interest.
International E&P Segment
We are engaged in oil and gas development and production across our international locations primarily in E.G., U.K. and
Libya. We include the results of our LPG processing plant, gas liquefaction operations and methanol production operations in
E.G. in our International E&P segment.
International E&P
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. Block D was unitized with the Alba field in second
quarter 2017. Operational availability from our company-operated facilities averaged approximately 99% in 2017.
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, under a long-term
contract at a fixed price per btu, is processed by the LPG plant. 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.
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 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 3.95 mmta in 2017. AMPCO had gross sales totaling approximately 1,100 mt in 2017. Methanol
production is sold to customers in Europe and the U.S.
United Kingdom – Our operated asset in the U.K. sector of the North Sea is the Brae area complex where we have a 42%
working interest in the South, Central, North and West Brae fields, a 39% working interest in the East Brae field, and a 28%
working interest in the nearby Braemar field. We own non-operated working interests in the Foinaven area complex, consisting
of a 28% working interest in the main Foinaven field, a 47% working interest in East Foinaven and a 20% working interest in
the T35 and T25 fields.
6
Libya – We hold a 16% non-operated working interest in the Waha concessions, which includes acreage located in the Sirte
Basin of eastern Libya. While civil and political unrest has interrupted operations in recent years, our production resumed in
October 2016 at our Waha concession. During December 2016, liftings resumed from the Es Sider crude oil terminal. During
2017 sales volumes and production continued, except for a brief interruption in March 2017 due to civil unrest.
Other International
Kurdistan Region of Iraq – We have non-operated interests in two blocks located north-northwest of Erbil: Atrush with a
15% working interest and Sarsang with a 20% working interest. In 2016, we relinquished to the Kurdistan Regional
Government our 45% operated working interest in the Harir block located northeast of Erbil.
Gabon – We hold a 100% participating interest and operatorship in the Tchicuate block where we have an exploration and
production sharing agreement.
In the third quarter 2017, we entered into separate agreements to sell certain non-core properties in our International E&P
segment, and a portion of this transaction closed during the 4th quarter 2017. See Item 8. Financial Statements and
Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.
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. Other International ("Other Int’l"), includes the U.K.
and the Kurdistan Region of Iraq. Approximately 72% of our proved reserves are located in OECD countries, with 70% located
within the U.S.
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, 2017.
December 31, 2017
Proved Developed Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Total proved developed reserves (mmboe)
Proved Undeveloped Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Total proved undeveloped reserves
(mmboe)
Total Proved Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Total proved reserves (mmboe)
Africa
U.S.
E.G.
Libya
Total
Other
Int'l
Total
from
Cont Ops
263
118
726
502
307
111
598
518
570
229
1,324
1,020
39
25
833
203
—
—
—
—
39
25
833
203
165
—
94
181
—
—
110
18
165
—
204
199
204
25
927
384
—
—
110
18
204
25
1,037
402
17
—
2
17
9
—
6
10
26
—
8
27
484
143
1,655
903
316
111
714
546
800
254
2,369
1,449
Of the total estimated proved reserves, approximately 55% was crude oil and condensate. As of December 31, 2017, our
estimated proved developed reserves totaled 903 mmboe or 62% and estimated proved undeveloped reserves totaling 546
mmboe or 38% of our total proved reserves. For additional detail on reserves, see Item 8. Financial Statements and
Supplementary Data - Supplementary Information on Oil and gas Producing Activities.
7
Productive and Drilling Wells
For our United States E&P and International E&P 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
Gross
Net
Gross
Net
Service Wells
Net
Gross
Drilling Wells
Net
Gross
33
—
—
—
—
33
13
—
—
—
—
13
2017
U.S.
E.G.
Libya
Total Africa
Other International
Total
2016
U.S. (a)
E.G.
Libya
Total Africa
Other International
Total
2015
U.S.
E.G.
Libya
Total Africa
Other International
Total
5,132
—
1,071
1,071
61
6,264
4,533
—
1,071
1,071
62
5,666
7,198
—
1,071
1,071
59
8,328
1,905
—
175
175
22
2,102
1,650
—
175
175
23
1,848
2,878
—
175
175
21
3,074
1,690
19
7
26
19
1,735
1,830
17
7
24
35
1,889
1,796
17
7
24
39
1,859
676
12
2
14
7
697
708
11
1
12
14
734
750
11
1
12
16
778
799
—
94
94
23
916
821
2
94
96
23
940
2,727
2
94
96
24
2,847
70
—
16
16
8
94
85
1
16
17
8
110
747
1
16
17
8
772
(a)
Reduction in December 31, 2016 gross and net productive wells and service wells is primarily due to the dispositions of certain conventional West Texas
and Wyoming assets in 2016. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information
about these dispositions.
8
Drilling Activity
For our United States E&P and International E&P segments, the table below sets forth, by geographic area, the number of
net productive and dry development and exploratory wells completed as of December 31 for the years represented.
Development
Exploratory
Oil
Natural
Gas
Dry
Total
Oil
Natural
Gas
Dry
Total
Total
107
—
—
—
—
107
64
—
—
—
—
64
135
—
—
—
1
136
27
—
—
—
—
27
12
—
—
—
—
12
36
1
—
1
—
37
—
—
—
—
—
—
—
—
—
—
—
11
—
—
—
—
11
134
—
—
—
—
134
76
—
—
—
—
76
182
1
—
1
1
184
88
—
—
—
—
88
70
—
—
—
—
70
49
—
—
—
—
49
16
—
—
—
—
16
27
—
—
—
—
27
48
—
—
—
—
48
—
—
—
—
—
—
—
—
—
—
—
—
1
1
—
1
—
2
104
—
—
—
—
104
97
—
—
—
—
97
98
1
—
1
—
99
238
—
—
—
—
238
173
—
—
—
—
173
280
2
—
2
1
283
2017
U.S.
E.G.
Libya
Total Africa
Other International
Total
2016
U.S.
E.G.
Libya
Total Africa
Other International
Total
2015
U.S.
E.G.
Libya
Total Africa
Other International
Total
Acreage
We believe we have satisfactory title to our United States E&P and International E&P properties in accordance with
standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time which 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 in our United
States E&P and International E&P segments as of December 31, 2017.
(In thousands)
U.S.
E.G.
Libya
Other Africa
Total Africa
Other International
Total
Developed
Undeveloped
Developed and
Undeveloped
Gross
Net
Gross
Net
Gross
Net
322
36
1,917
136
— 12,909
277
13,322
257
277
313
32
667
1,330
103
2,108
277
2,488
63
15,496
3,881
1,529
1,008
82
67
12,909
2,108
—
—
12,991
2,175
86
31
14,606
3,214
388
54
—
277
331
171
890
9
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, licenses or concessions, additional undeveloped acreage will expire
in future years. We plan to continue the terms of certain of these licenses and concession areas or retain leases through
operational or administrative actions.
Net Sales Volumes
Year Ended December 31,
2017
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Total sales volumes (mboed)
2016
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Total sales volumes (mboed)
2015
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Africa
U.S.
E.G.
Libya
Other
Int'l
Cont
Ops
Disc
Ops
Total
133
43
348
—
234
131
40
314
—
223
21
11
459
—
109
20
11
425
—
102
19
—
4
—
20
3
—
—
—
3
12
1
22
—
16
12
—
28
—
17
185
55
833
—
379
166
51
767
—
345
—
—
—
18
18
—
—
—
48
48
171
39
351
—
269
19
10
410
—
97
—
—
—
—
—
14
—
21
—
18
204
49
782
—
384
—
—
—
45
45
185
55
833
18
397
166
51
767
48
393
204
49
782
45
429
(a)
Total sales volumes (mboed)
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid
hydrocarbons.
Includes natural gas acquired for injection and subsequent resale.
(b)
(c) Upgraded bitumen excluding blendstocks.
Average Production Cost per Unit (a)
Africa
U.S.
E.G.
Libya
(Dollars per boe)
2017
2016
2015
(a)
$
$
9.23
11.02
12.62
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.
29.72
29.36
38.42
9.49
9.84
10.65
6.08
N.M.
N.M.
7.90
8.41
9.54
2.12
2.17
2.37
$
$
$
$
Other Int'l
26.61
$
23.13
27.23
Cont Ops
Disc Ops
Total
N.M. Not meaningful information due to limited sales.
10
Average Sales Price per Unit(a)
(Dollars per unit)
2017
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
2016
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
2015
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
(a)
(b)
Africa
U.S.
E.G.
Libya
Total
$ 49.35
20.55
2.84
—
$ 38.57
13.15
2.38
—
$ 46.02
1.00
0.24
—
$ 38.85
1.00
0.24
—
(b)
(b)
(b)
(b)
$ 60.72
—
5.03
—
$ 57.69
—
—
—
$ 53.11
1.00
0.28
—
$ 40.95
1.00
0.24
—
Other
Int'l
$ 52.66
39.65
6.28
—
$ 43.21
26.41
4.80
—
Disc
Ops
$ —
—
—
47.39
$ —
—
—
37.57
Total
$ 50.38
16.65
1.51
47.39
$ 39.23
10.68
1.26
37.57
$ 42.83
1.00
0.24
—
Excludes gains or losses on commodity derivative instruments.
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 E&P Segment.
$ 43.50
13.37
2.66
—
$ 53.91
32.53
6.85
—
$ 42.83
1.00
0.24
—
$ —
—
—
40.13
$ —
—
—
—
$ 44.14
11.16
1.50
40.13
(b)
(b)
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.
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, 2017, 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 liquids (mbbld)
Natural gas (mmcfd)
Bakken
Crude and condensate (mbbld)
Natural gas (mmcfd)
Oklahoma
Natural gas (mmcfd)
2018
2019
2020
Thereafter
Commitment
Period Through
95
1
168
10
2
—
65
1
168
10
2
90
51
—
168
10
2
—
—
46 - 70
5 - 10
2 - 25
118
110 - 148
2020
2020
2022
2027
2027
2030
All of these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if
production is inadequate. 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.
11
Competition
Competition exists in all sectors of the oil and gas industry and we compete with major integrated and independent oil and
gas companies, as well as national oil companies. 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.
Environmental, Health and Safety Matters
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.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and
safety at the national, state and local levels. 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, 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.
New laws have been enacted 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.
For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation,
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.
Air and Climate Change
Environmental advocacy groups and regulatory agencies in the United States and other countries have focused
considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their potential role in
climate change. Developments in greenhouse gas initiatives may affect us and other similarly situated companies operating in
the oil and gas industry. As part of our commitment to environmental stewardship, we estimate and publicly report greenhouse
gas emissions from our operations. We are working to continuously improve the accuracy and completeness of these estimates.
In addition, we continuously strive to improve operational and energy efficiencies through resource and energy conservation
where practicable and cost effective.
Government entities have filed lawsuits in California and New York 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 six of these lawsuits in California, 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.
The EPA finalized a more stringent National Ambient Air Quality Standard ("NAAQS") for ozone in October 2015. This
more stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which we
operate, which 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. The EPA anticipates promulgating final area designations under the new
standard in the first half of 2018. 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
12
that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how
they will be implemented. The EPA's final rule has been judicially challenged by both industry and other interested parties, and
the outcome of this litigation may also impact implementation and revisions to the rule.
In November 2016, the Bureau of Land Management (“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. BLM issued a two-year stay of
these requirements in December 2017 and has indicated that the requirements could be rescinded or significantly revised in the
future. If not withdrawn or significantly revised, this rule is expected to result in additional costs of compliance as well as
increased monitoring, recordkeeping and recording for some of our facilities. If we are unable to comply with the terms of
these regulations, we could be required to forego certain operations. These regulations may also result in administrative, civil
and/or criminal penalties for non-compliance.
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. 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.
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 Clean Water Act ("CWA") and its various programs. While these regulations were finalized largely
as proposed in 2015, the rule has been stayed by the courts pending a substantive decision on the merits. If this rule is
ultimately implemented, 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.
For additional information, see Item 1A. Risk Factors.
Concentrations of Credit Risk
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 2017, sales to Vitol and each of their respective affiliates
accounted for approximately 10% of our total revenues. In 2016, sales to Valero Marketing and Supply, Tesoro Petroleum, and
Flint Hills Resources and each of their respective affiliates accounted for approximately 13%, 11% and 10% of our total
revenues. In 2015, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues.
Trademarks, Patents and Licenses
We currently hold a number of U.S. and foreign patents. Although in the aggregate our trademarks, patents and licenses
are important to us, we do not regard any single trademark, patent, license or group of related trademarks, patents or licenses as
critical or essential to our business as a whole.
Employees
We had approximately 2,300 active, full-time employees as of December 31, 2017.
13
Executive Officers of the Registrant
The executive officers of Marathon Oil and their ages as of February 1, 2018, are as follows:
Lee M. Tillman
Dane E. Whitehead
T. Mitch Little
Reginald D. Hedgebeth
Patrick J. Wagner
Catherine L. Krajicek
Gary E. Wilson
56
56
54
50
53
56
56
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Executive Vice President—Operations
Senior Vice President, General Counsel and Secretary
Executive Vice President-Corporate Development and Strategy
Vice President—Conventional
Vice President, Controller and Chief Accounting Officer
Mr. Tillman was appointed president and chief executive officer in August 2013. Mr. Tillman is also a member of our
Board of Directors. 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. Little was appointed executive vice president of operations in August 2016 after having served as vice president,
conventional since December 2015, vice president international and offshore exploration and production operations since
September 2013, and as vice president, international production operations since September 2012. Prior to that, Mr. Little was
resident manager of our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little
joined Marathon Oil in 1986 and has since held a number of engineering and management positions of increasing responsibility.
Mr. Hedgebeth was appointed senior vice president, general counsel and secretary in April 2017. Between 2009 and 2017
Mr. Hedgebeth served as general counsel, corporate secretary and chief compliance officer for Spectra Energy Corp (oil and
natural gas pipeline company) and general counsel for Spectra Energy Partners, LP. Before joining Spectra Energy Mr.
Hedgebeth served as senior vice president, general counsel and secretary with Circuit City Stores, Inc. (consumer electronics
company), and vice president of legal for The Home Depot, Inc. (home improvement supplies retailing company).
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.
Ms. Krajicek was appointed vice president—conventional assets in August 2016 after having served as vice president of
technology and innovation since December 2015. Prior to that, Ms. Krajicek served as vice president, health, environment,
safety and security from January 2015 through December 2015. In January 2018 Ms. Krajicek announced her plans to retire
effective April 1, 2018. Ms. Krajicek joined Marathon Oil in 2007 and has since held a number of positions of increasing
responsibility. Prior to joining the Company, Ms. Krajicek spent 22 years with Conoco and then ConocoPhillips (a
multinational energy corporation), where she held a variety of reservoir engineering and asset management and development
management positions for upstream and mid-stream businesses under development, both in the U.S. and internationally.
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 corporate accounting from February 2014 through
September 2014, director global operations services finance from October 2012 through February 2014, director controls and
14
reporting from April 2011 through September 2012, and international finance manager from September 2009 through March
2011.
Available Information
Our website is www.marathonoil.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and 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 our Investor Relations office.
The public may read and copy any materials we file with the SEC at its Public Reference Room at 100 F Street, NE,
Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at
1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements and
other information regarding issuers that file electronically with the SEC.
Additionally, we make available free of charge on our website:
•
•
•
our Code of Business Conduct and Code of Ethics for Senior Financial Officers;
our Corporate Governance Principles; and
the charters of our Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating
Committee and Health, Environmental, Safety and Corporate Responsibility Committee.
15
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.
A substantial decline in crude oil and condensate, NGLs and natural gas prices would reduce our operating results and
cash flows and could adversely impact our future rate of growth and the carrying value of our assets.
The markets for crude oil and condensate, NGLs and natural gas have been volatile and are likely to continue to be volatile
in the future, causing prices to fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent
on the prices we receive for our crude oil and condensate, NGLs and natural gas. Many of the factors influencing prices of
crude oil and condensate, NGLs and natural gas are beyond our control. These factors include:
• worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas;
•
•
•
•
•
•
•
•
•
•
•
•
•
the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas;
the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production
controls;
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;
the effect of conservation efforts;
epidemics or pandemics;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxes; and
general economic conditions worldwide.
The long-term effects of these and other factors on the prices of crude oil and condensate, NGLs and natural gas are
uncertain. Historical declines in commodity prices have adversely affected our business by:
•
•
•
•
•
reducing the amount of crude oil and condensate, NGLs and natural gas that we can produce economically;
reducing our revenues, operating income and cash flows;
causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
requiring us to impair the carrying value of our assets;
reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and
natural gas; and
•
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
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, natural gas and our historical synthetic crude oil reserves
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 and third-party consultants. Prior to 2016, the synthetic
16
crude oil reserves estimates, included in discontinued operations, were prepared by GLJ, a third-party consulting firm
experienced in working with oil sands. Reserves were valued based on SEC pricing for the periods ended December 31, 2017,
2016 and 2015, as well as other conditions in existence at those dates. The table below provides the 2017 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)
SEC Pricing 2017
$
$
$
$
51.34
2.98
54.39
22.03
If commodity prices were to decrease by approximately 10% below average prices used to estimate 2017 proved reserves
(see table above), we would not expect price related reserve revisions to have a material impact on proved reserve volumes.
Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among
other things.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground
accumulations of crude oil and condensate, NGLs and natural gas that cannot be directly measured. Estimates of economically
producible reserves and of future net cash flows depend on a number of variable factors and assumptions, including:
•
•
•
•
•
location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
historical production from the area, compared with production from other analogous producing areas;
the assumed impacts of regulation by governmental agencies;
assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
industry economic conditions, levels of cash flows from operations and other operating considerations.
As a result, different petroleum engineers and geoscientists, each using industry-accepted geologic and engineering
practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the
same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ
materially from the estimated amounts:
•
•
•
the amount and timing of production;
the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
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 will 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 will decline. Creating and maintaining an inventory of
prospects for future production depends on many factors, including:
•
•
•
•
•
obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas in promising areas;
drilling success;
the ability to complete projects timely and cost effectively;
the ability to find or acquire additional proved reserves at acceptable costs; and
the ability to fund such activity.
17
Future exploration and drilling results are uncertain and involve substantial costs.
Drilling for crude oil and condensate, NGLs and natural gas involves numerous risks, including the risk that we may not
encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
•
•
•
•
•
•
•
•
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
inflation in exploration and drilling costs;
fires, explosions, blowouts or surface cratering;
lack of access to pipelines or other transportation methods; and
shortages or delays in the availability of services or delivery of equipment.
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, including abandonment obligations, 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 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,
including abandonment obligations, to us. The inability of our joint venture partners to fund their portion of the costs under our
joint venture 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;
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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.
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
deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and 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.
18
We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in
environmental, health, safety and security laws and regulations, and, as a result, our business, financial condition,
results of operations and cash flows could be materially and adversely affected.
Our businesses are subject to numerous laws, regulations and other requirements relating to the protection of the
environment, including those relating to the discharge of materials into the environment such as the venting or flaring of natural
gas, waste management, pollution prevention, greenhouse gas emissions 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. 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. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices
of our products, our operating results will 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.
We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility
for climate change will continue, with the potential for further 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
countries where we operate, including the U.S. and the European Union. 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 agreement includes provisions
that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions
should be lowered. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and gas
industry. Finalization of new legislation, regulations or international agreements in the future could result in increased costs to
operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer
and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures
could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and
condensate, NGLs and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.
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.
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.
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State and federal regulatory agencies recently 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 recently 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.
Worldwide political and economic developments and changes in law or policy could adversely affect our operations and
materially reduce our profitability and cash flows.
Local political and economic factors in global markets could have a material adverse effect on us. A total of 38% of our
crude oil and condensate, NGLs and natural gas related to continuing operations in 2017 was derived from production outside
the U.S. and 30% of our proved reserves of crude oil and condensate, NGLs and natural gas as of December 31, 2017 were
located outside the U.S. We are, therefore, subject to the political, geographic and economic risks and possible terrorist
activities or other armed conflict attendant to doing business within or outside of the U.S. There are many risks associated with
operations in countries such as E.G., Gabon, the Kurdistan Region of Iraq and Libya, and in global markets including:
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changes in governmental policies relating to crude oil and condensate, NGLs or natural gas and taxation;
other political, economic or diplomatic developments and international monetary fluctuations;
political and economic instability, war, acts of terrorism, armed conflict and civil disturbances;
the possibility that a 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; and
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fluctuating currency values, hard currency shortages and currency controls.
For the past several years, there have been varying degrees of political instability and public protests, including
demonstrations which have been marked by violence and numerous incidences of terrorist acts, within some countries in the
Middle East and Africa. Some political regimes in these countries are threatened or have changed as a result of such unrest.
If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in
governments that are hostile to the U.S. These may have the following results, among others:
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volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic
growth rates and reduced demand for our products;
negative impact on the world crude oil supply if transportation avenues are disrupted;
security concerns leading to the prolonged evacuation of our personnel;
damage to, or the inability to access, production facilities or other operating assets; and
inability of our service and equipment providers to deliver items necessary for us to conduct our operations.
Continued hostilities in the Middle East and Africa and the occurrence or threat of future terrorist attacks, or other armed
conflict, could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity
could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future
growth prospects. These risks could lead to increased volatility in prices for crude oil and condensate, NGLs and natural gas.
In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to
access capital and to obtain the insurance coverage that we consider adequate.
20
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 law could also adversely affect our results, including new regulations resulting in 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.
Our level of indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2017, our total debt was $5.5 billion, with no debt due within the next 24 months. Our indebtedness
could have important consequences to our business, including, but not limited to, the following:
• we may be more vulnerable to general adverse economic and industry conditions;
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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 Credit Agreement stipulates that our total debt to 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
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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, 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 15 to the consolidated
financial statements for a discussion of debt obligations.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital, which could adversely
affect our business.
We receive debt ratings from the major credit rating agencies in the United States. Due to the decline in crude oil and U.S.
natural gas prices in recent years, credit rating agencies reviewed companies in the energy industry, including us. At December
31, 2017, our corporate credit ratings were: Standard & Poor's Global Ratings Services BBB- (stable); Fitch Ratings BBB
(stable); and Moody's Investor Services, Inc. Ba1 (stable). The credit rating process is contingent upon a number of factors,
many of which are beyond our control. A downgrade of our credit ratings 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 revolving 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 unsecured revolving credit facility. Limitations on our ability to access capital could adversely impact the level of our
capital spending program, our ability to manage our debt maturities, or our flexibility to react to changing economic and
business conditions.
21
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 and natural gas, we, from time to time, enter into crude oil 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.
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
systems and related infrastructure security vulnerabilities. We may also be subject to regulatory investigations or litigation
relating from cybersecurity issues.
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 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. Both the cost and availability of pipelines,
rail cars, trucks, or vessels to transport our crude oil could be adversely impacted by new and expected state or federal
regulations relating to transportation of crude oil.
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.
22
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.
Many of our major projects and operations are conducted with partners, 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 partners 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, noncompliance with applicable laws and
regulations or improper activities by or on behalf of one or more of our partners could have a significant negative impact on our
business and reputation.
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 E&P and International E&P 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. For example, due to historical hurricane activity, the availability of
insurance coverage for windstorms has changed and, in some instances, it is uneconomical. As a result, our exposure to losses
from future windstorm activity has increased.
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 have filed lawsuits in California and New York 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 six of these lawsuits in California, along with
numerous other companies. Similar lawsuits may be filed in other jurisdictions. The ultimate outcome and impact to us cannot
23
be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in
the future.
In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be
no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s
ability to satisfy its indemnification obligations will not be impaired in the future.
Pursuant to the Separation and Distribution Agreement and the Tax Sharing Agreement we entered into with MPC in
connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seek to hold us
responsible for any of the liabilities that MPC agreed to retain or assume, and there can be no assurance that the indemnification
from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its
indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are
held liable, we may be temporarily required to bear these losses ourselves.
The spin-off could result in substantial tax liability.
We obtained a private letter ruling from the IRS substantially to the effect that the distribution of shares of MPC common
stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections
355 and 368 and related provisions of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). If the factual
assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in
any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution
such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather,
the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those
representations could invalidate the ruling. In connection with the spin-off, we also obtained an opinion of outside counsel,
substantially to the effect that, the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us
and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the Code. The
opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and
representations as to factual matters made by MPC and us which, if inaccurate or incomplete in any material respect, would
jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and
there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such
challenge would not prevail.
If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify
under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-
off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the
shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent
of our accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that
exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s
tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to
tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would
recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.
Under the terms of the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC is
generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain
related transactions were to fail to qualify for tax-free treatment as a result of actions taken, or breaches of representations and
warranties made in the Tax Sharing Agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related
transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we
would be responsible for all such taxes.
We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil common
stock.
Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more
classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights,
including preferences over Marathon Oil common stock respecting dividends and distributions, as our Board of Directors
generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce
the value of Marathon Oil common stock. For example, we could grant holders of preferred stock the right to elect some
number of our directors in all events or on the happening of specified events or the right to veto specified transactions.
Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could
affect the residual value of the common stock.
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Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and general character of our principal crude oil and condensate, NGLs and natural gas properties and
facilities, and other important physical properties have been described by segment under Item 1. Business.
Estimated net proved crude oil and condensate, NGLs and natural gas reserves are set forth in Item 8. Financial Statements
and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved
Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.
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 24 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,
2017, under federal and state environmental laws.
Government entities have filed lawsuits in California and New York 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 six of these lawsuits in California, 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, 2017, 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.
If our assumptions relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange ("NYSE"). As of
January 31, 2018, there were 31,472 registered holders of Marathon Oil common stock.
The following table reflects high and low sales prices for Marathon Oil common stock and the related dividend per share
by quarter for the past two years:
(Dollars per share)
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Full Year
High Price
$18.18
$16.60
$13.73
$17.26
$18.18
2017
Low Price
$14.61
$11.35
$10.77
$13.48
$10.77
Dividends High Price
$12.82
$15.27
$16.80
$18.80
$18.80
$0.05
$0.05
$0.05
$0.05
$0.20
2016
Low Price
$6.73
$10.53
$12.90
$12.78
$6.73
Dividends
$0.05
$0.05
$0.05
$0.05
$0.20
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 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, 2017, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities
Exchange Act of 1934:
Period
10/01/17 – 10/31/17
11/01/17 – 11/30/17
12/01/17 – 12/31/17
Total
Total Number of
Shares
Purchased(a)
Average
Price Paid
per Share
49,046
2,813
—
51,859
$13.38
$14.62
—
$13.45
Total Number of
Shares Purchased
as Part of
Publicly
Announced Plans
or Programs(b)
Approximate
Dollar Value of
Shares that May
Yet Be
Purchased
Under the Plans
or Programs(b)
1,500,285,529
— $
— $
1,500,285,529
— $
1,500,285,529
—
(a)
(b)
51,859 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
In January 2006, we announced a $2.0 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 $2.0 billion in July 2007, and by $1.2 billion in December 2013, for
a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of December 31, 2017 is $1.5 billion. No repurchases were
made under the program in 2017.
26
Item 6. Selected Financial Data
(In millions, except per share data)
Statement of Income Data(a)(b)(c)
Revenues
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Per Share Data(a)(b)(c)
Basic:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Diluted:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Statement of Cash Flows Data(b)
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
(a)
2017
Year Ended December 31,
2015
2016
2014
$
4,373
(830)
(4,893)
(5,723)
$
3,170
(2,087)
(53)
(2,140)
$
4,635
(1,701)
(503)
(2,204)
9,238
710
2,336
3,046
(0.97) $
(5.76) $
(6.73) $
(0.97) $
(5.76) $
(6.73) $
(2.55) $
(0.06) $
(2.61) $
(2.55) $
(0.06) $
(2.61) $
(2.51) $
(0.75) $
(3.26) $
(2.51) $
(0.75) $
(3.26) $
1.04
3.44
4.48
1.04
3.42
4.46
2013
9,731
710
1,043
1,753
1.01
1.48
2.49
1.00
1.47
2.47
$
$
$
$
$
$
$
(1,974) $
170
0.20
$
(1,204) $
162
0.20
$
(3,485) $
460
0.68
(4,937) $
543
$0.80
(4,170)
508
$0.72
$
22,012
5,494
$
31,094
6,581
32,311
7,268
$
$
35,983
5,285
35,588
6,352
$
$
$
$
$
$
$
$
$
$
Includes impairments to producing properties of $229 million, $67 million, $381 million, $132 million and $96 million in 2017, 2016, 2015, 2014 and
2013 and impairments to unproved properties of $246 million, $195 million, $655 million, $306 million and $572 million in 2017, 2016, 2015, 2014 and
2013 (see Item 8. Financial Statements and Supplementary Data – Note 10 to the consolidated financial statements). Includes a goodwill impairment of
$340 million in 2015 related to the U.S. E&P reporting unit (see Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated
financial statements).
(b) We closed on the sale of our Canada business in 2017 which resulted in an after-tax non-cash impairment charge of $4.96 billion and our Angola assets
and Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements). The
applicable periods have been recast to reflect as discontinued operations.
(c) December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million (see Item 8. Financial
Statements and Supplementary Data – Note 9 to the consolidated financial statements).
27
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 segments is organized and managed based upon both geographic location and the nature of the products and
services it offers.
• United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United
States
•
International E&P – 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 Summary
During 2017, we continued to strengthen our balance sheet, transform our portfolio and manage our capital and operating
costs. Through multiple financing transactions in 2017, we have reduced total debt by approximately $1.75 billion which will
result in a reduction to our future annual interest expense of approximately $115 million. Additionally, we closed on the sale of
our Canadian business for approximately $2.5 billion and acquired acreage in the Permian basin, including over 70,000 net
acres in Northern Delaware for approximately $1.9 billion.
As discussed in Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements, we
closed on the sale of our Canadian business, which has been reflected as discontinued operations and is excluded from
operations in all periods presented.
Key highlights include the following:
Liquidity and corporate financing
• Ended 2017 with liquidity of $4.0 billion, comprised of $563 million in cash and cash equivalents and an undrawn
$3.4 billion revolving credit facility, which was increased from $3.3 billion in July 2017. Remaining proceeds of $750
million from the sale of our Canadian business are scheduled to be received in the first quarter of 2018.
•
•
In third quarter 2017, we issued $1 billion of 4.4% senior unsecured notes due in 2027 and redeemed approximately
$1.75 billion of debt due in 2017, 2018 and 2019. This offering and redemption reduced our future annual interest
expense by approximately $64 million.
In December 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction
that preserved our ability to remarket up to $1 billion of tax-exempt municipal bonds prior to 2037. This redemption
reduced our future annual interest expense by approximately $51 million.
Simplifying our portfolio
• We closed on the sale of our Canadian business for approximately $2.5 billion with over $1.8 billion in proceeds
received to date and $750 million to be received in first quarter 2018.
• We closed on multiple Permian basin acquisitions for approximately $1.9 billion of cash on hand.
Financial and Operational results
• Total 2017 net sales volumes from continuing operations are 379 mboed, including Libya, which is 10% higher
compared to 2016. This includes a 12% increase in sales volumes from the U.S resource plays to 217 mboed within
our United States E&P segment.
• Due to improved cost structure and higher sales volumes, our production expense rate in our United States E&P
segment decreased 7% to $5.57 per boe in 2017 compared to last year. In our International E&P segment, our
production expense rate decreased 14% to $4.33 per boe in 2017 primarily due to an increase in sales volumes in E.G.
and Libya.
• Added proved reserves of 193 mmboe for a reserve replacement ratio from continuing operations of 140%.
• Net cash provided by operating activities in 2017 was $2.0 billion, compared to $901 million in 2016 primarily as a
result of improved price realizations, increased sales volumes and lower unit production expenses.
28
• Our net loss per share from continuing operations was $0.97 in 2017 as compared to a net loss per share of $2.55 last
year. Included in the 2017 net loss are:
An increase in sales and other operating revenues of over 40% to $4.2 billion primarily due to improved price
realizations and increased sales volumes.
Our sales volumes from continuing operations increased 10% while production expense remained flat during 2017
as a result of improved cost structure.
Depreciation, depletion and amortization expense increased 10% to $2.4 billion due to our increase in sales
volumes from continuing operations.
Exploration and impairment expenses increased by $248 million to $638 million, year over year, primarily due to
non-cash impairment charges on proved and unproved properties primarily as a result of the anticipated sales of
certain non-core international assets and due to lower forecasted long-term commodity prices.
Our provision for income taxes was $376 million in 2017 primarily as a result of our full valuation allowance on
our net federal deferred tax assets throughout 2017 and the effects of our foreign operations. See Item 8. Financial
Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion of the effects
of U.S. Tax Reform Legislation.
Outlook
Capital Development Program
Our $2.3 billion 2018 Capital Development Program will be over 90% allocated to our U.S. resource plays. Almost 60%
of this development budget will be allocated to the high-return Eagle Ford and Bakken assets, which have demonstrated step-
change performance improvements while operating at scale. Approximately one-third of the development budget will be
allocated to our Northern Delaware and Oklahoma assets, where the majority of drilling activity will be transitioning to multi-
well pads, while continuing strategic delineation and appraisal.
Our 2018 Capital Development Program is broken down by reportable operating segment in the table below:
(In millions)
United States E&P
Eagle Ford
Bakken
Oklahoma
Northern Delaware
Total United States E&P
International E&P and corporate other (a)
Total Capital Development Program
Capital Development Program
$
$
$
710
590
410
380
2,090
210
2,300
(a)
International E&P and corporate other includes our International E&P segment and other corporate items
Operations
Our net sales volumes from continuing operations, including Libya, averaged 379 mboed, 345 mboed and 385 mboed for
2017, 2016 and 2015, respectively. This 10% increase in 2017 was primarily due to new wells to sales in our U.S. resource
plays, our acquisitions in Northern Delaware and the resumption of sales in Libya.
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 E&P (mboed)
International E&P (a) (mboed)
Total Continuing Operations (mboed)
(10)%
(a) Years ended December 31, 2017, 2016 and 2015 include net sales volumes relating to Libya of 20 mboed, 3 mboed and none, respectively.
(17)%
2017
2016
10%
19%
5 %
223
345
234
145
379
122
2015
269
116
385
Increase
(Decrease)
5%
Increase
(Decrease)
29
United States E&P
The following tables provide additional detail regarding net sales volumes, sales mix and operational drilling activity for
our significant operations within this segment:
Net Sales Volumes
Equivalent Barrels (mboed)
Oklahoma
Eagle Ford
Bakken
Northern Delaware
Other United States(a)
Total United States E&P (mboed)
2017
Increase
(Decrease)
2016
Increase
(Decrease)
2015
54
101
56
6
17
234
54%
(4)%
4%
100%
(41)%
5%
35
105
54
—
29
223
40%
(22)%
(8)%
—%
(43)%
(17)%
25
134
59
—
51
269
(a) Year ended December 31, 2017 includes decreases of 14 mboed, consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood
assets in West Texas and New Mexico in 2016. Year ended December 31, 2016 decreases relating to assets sold were 23 mboed, primarily consisting of
Wyoming, West Texas, East Texas, North Louisiana and certain Gulf of Mexico assets. See Item 8. Financial Statements and Supplementary Data - Note
5 to the consolidated financial statements for information about these dispositions.
Sales Mix - U.S. Resource Plays - 2017
Oklahoma
Crude oil and condensate
Natural gas liquids
Natural gas
28%
26%
46%
Eagle
Ford
58%
21%
21%
Bakken
Northern
Delaware
83%
10%
7%
66%
8%
26%
Total
57%
19%
24%
Drilling Activity - U.S. Resource Plays
Gross Operated
2017
2016
2015
Oklahoma:
Wells drilled to total depth
Wells brought to sales
Eagle Ford:
Wells drilled to total depth
Wells brought to sales
Bakken:
Wells drilled to total depth
Wells brought to sales
Northern Delaware
Wells drilled to total depth
Wells brought to sales
86
73
182
157
90
39
27
18
33
28
168
168
3
13
—
—
20
21
251
276
35
56
—
—
•
•
•
•
Eagle Ford – Our net sales volumes were 101 mboed in 2017, 4% lower compared to 2016. We brought fewer wells
to sales in 2017, while we increased well productivity through completion optimization and efficiency gains.
Bakken – Our net sales volumes were 56 mboed in 2017 compared to 54 mboed in 2016. In 2017, we improved well
performance with continued application of high intensity completions. During the year, we set a new record in the
Williston Basin for the highest 30-day initial production oil rate.
Oklahoma – Our net sales volumes in 2017 increased by 54% to 54 mboed compared to year ended 2016. Our activity
during 2017 was concentrated in the STACK and was focused on leasehold capture, delineation drilling and infill
spacing pilots.
Northern Delaware – Our net sales volumes were 6 mboed in 2017 which reflected a partial year of production
following the second quarter 2017 closing of the BC Operating and Black Mountain assets. During 2017 we focused
our activity on delineation and leasehold capture across our position in Eddy and Lea Counties, New Mexico.
30
International E&P
The following table provides net sales volumes from continuing operations within this segment:
Net Sales Volumes
Equivalent Barrels (mboed)
Equatorial Guinea
United Kingdom(a)
Libya
Other International
Total International E&P (mboed)
Equity Method Investees
LNG (mtd)
Methanol (mtd)
Condensate & LPG (boed)
Includes natural gas acquired for injection and subsequent resale.
(a)
2017
109
14
20
2
145
6,423
1,374
14,501
Increase
(Decrease)
7%
(18)%
567%
100%
19%
9%
1%
8%
2016
102
17
3
—
122
5,874
1,358
13,430
Increase
(Decrease)
5%
(11)%
100%
—%
5%
—%
45%
10%
2015
97
19
—
—
116
5,884
937
12,208
•
•
•
Equatorial Guinea – Net sales volumes in 2017 were higher than 2016 as a result of the completion and start-up of our
Alba field compression project in mid-2016 and lower volumes in first quarter 2016 due to a planned turnaround.
Additionally, in April 2017 we received host government approval to develop Block D offshore E.G. through
unitization with the Alba field.
United Kingdom – Net sales volumes in 2017 decreased compared to 2016 primarily as a result of planned turn-around
activity at the Brae and Foinaven complexes and the temporary shut-down of the outside-operated Forties Pipeline
System during fourth quarter 2017.
Libya – While civil and political unrest has interrupted operations in recent years, our production resumed in October
2016. During December 2016, liftings resumed from the Es Sider crude oil terminal. During 2017, sales volumes and
production continued, except for a brief interruption in March 2017 due to civil unrest.
Market Conditions
Crude oil, natural gas and NGL benchmarks increased in 2017 as compared to the same period in 2016. As a result, we
experienced increased price realizations associated with those benchmarks. We continue to expect crude oil, natural gas and
NGLs benchmark prices to remain volatile based on global supply and demand, which will result in increases or decreases in
our price realizations. 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 commodity prices could impact us. Additional detail on
market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our
operating segments, follows.
31
United States E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas
for 2017, 2016 and 2015:
Average Price Realizations (a)
Crude Oil and Condensate (per bbl) (b)
Natural Gas Liquids (per bbl)
Total Liquid Hydrocarbons (per bbl)
Natural Gas (per mcf) (c)
Benchmarks
WTI crude oil average of daily prices (per bbl)
LLS crude oil average of daily prices (per bbl)
Mont Belvieu NGLs (per bbl) (d)
Henry Hub natural gas settlement date average (per mmbtu)
2017
Increase
(Decrease)
2016
Increase
(Decrease)
2015
$49.35
20.55
42.31
2.84
$50.85
54.04
23.76
3.11
28%
56%
29%
19%
17%
20%
37%
26%
$38.57
13.15
32.71
2.38
$43.47
45.02
17.40
2.46
(11)%
(2)%
(14)%
(11)%
(11)%
(14)%
3 %
(8)%
43.50
13.37
37.85
2.66
48.76
52.33
16.94
2.66
(a)
(b)
(c)
Excludes gains or losses on commodity derivative instruments.
Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations per barrel by $0.75,
$0.92, and $1.24 for 2017, 2016, and 2015.
Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods
presented.
(d) Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the
quality and location of the product.
Natural gas liquids – The majority of our NGLs volumes are sold at reference to Mont Belvieu prices.
Natural gas – A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month
indices relative to our specific producing areas.
International E&P
The following table presents our average price realizations and the related benchmark for crude oil for 2017, 2016 and
2015:
Average Price Realizations
Crude Oil and Condensate (per bbl)
Natural Gas Liquids (per bbl)
Total Liquid Hydrocarbons (per bbl)
Natural Gas (per mcf)
Benchmark
Brent (Europe) crude oil (per bbl)(a)
2017
Increase
(Decrease)
2016
(Decrease)
2015
$53.05
3.15
43.36
0.55
27%
49%
35%
6%
$41.70
2.11
32.10
0.52
(12)%
(25)%
(12)%
(24)%
$47.50
2.81
36.67
0.68
$54.25
25%
$43.55
(17)%
$52.35
(a) Average of monthly prices obtained from the United States Energy Information Agency website.
Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from
the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba
Plant. The Alba Plant extracts NGLs and secondary condensate, which have been supplied under a long-term contract at a fixed
price, leaving dry natural gas. The extracted NGLs and secondary condensate are sold by Alba Plant at market prices, with our
share of its income/loss reflected in income from equity method investments, and the dry natural gas from Alba Plant is
supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices
for condensate, NGLs and natural gas will not fully track market price movements. Because of the location and limited local
demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to
be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or
similar circumstances. EGHoldings and AMPCO process the gas into LNG and methanol, which are sold at market prices, with
our share of their income/loss reflected in the income from equity method investments line item on the Consolidated Statements
of Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later
production.
32
Consolidated Results of Operations: 2017 compared to 2016
Sales and other operating revenues, including related party are summarized by segment in the following table:
(In millions)
Sales and other operating revenues, including related party
United States E&P
International E&P
Segment sales and other operating revenues, including related party
Unrealized gain (loss) on commodity derivative instruments
Sales and other operating revenues, including related party
Year Ended December 31,
2017
2016
$
$
3,138 $
1,154
4,292
(81)
4,211 $
2,375
665
3,040
(110)
2,930
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.
(In millions)
Year Ended
December 31,
2016
Increase (Decrease) Related to
Net Sales
Volumes
Price Realizations
Year Ended
December 31,
2017
$
United States E&P Price-Volume Analysis (a)
Liquid hydrocarbons
Natural gas
Realized gain on commodity
derivative instruments
Other sales
Total
$
International E&P Price-Volume Analysis
Liquid hydrocarbons
Natural gas
Other sales
Total
$
$
$
2,041
274
44
16
2,375
$
546
87
32
665
$
619
58
$
264
4
66
29
205
6
$
$
$
$
2,726
361
45
6
3,138
1,015
97
42
1,154
(a) Year ended December 31, 2016 includes sales volumes of 14 mboed on an annualized basis relating to assets sold when compared to 2017, primarily
consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood assets in West Texas and New Mexico in 2016.
Marketing revenues decreased $78 million in 2017 from 2016, primarily as a result of lower marketed volumes in the
United States E&P segment due to non-core asset dispositions. Marketing activities include the purchase of commodities from
third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve
flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can
fluctuate from period to period.
Income from equity method investments increased $81 million primarily due to higher price realizations from LPG at our
Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement in net sales
volumes primarily driven by the completion of the Alba field compression project in E.G. during the second half of 2016.
Net gain on disposal of assets decreased $331 million in 2017 from 2016. This decrease was primarily related to the sale
of non-core assets in the first half of 2016 in Wyoming, West Texas and New Mexico, and the Gulf of Mexico. See Item 8.
Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these
dispositions.
Other income increased $25 million in 2017 from 2016. This increase was primarily a result of a downward revision in
U.K. estimated asset retirement costs as well as timing of abandonment activities in the U.K. See Item 8. Financial Statements
and Supplementary Data - Note 11 to the consolidated financial statements for detail about our asset retirement obligation.
Production expenses remained nearly flat during 2017 while our sales volumes from continuing operations increased.
During 2017, our production expense rate (expense per boe) for United States E&P was lower primarily due to the disposition
of higher cost non-core assets in Wyoming. The International E&P expense rate decreased in the year of 2017 primarily due to
33
an increase in sales volumes in E.G. and Libya, combined with lower maintenance costs in E.G.
($ per boe)
Production Expense Rate
United States E&P
International E&P
2017
2016
$5.57
$4.33
$5.96
$5.05
Marketing expenses decreased $77 million in 2017 from the prior year, consistent with the decrease in marketing revenues
discussed above.
Other operating expenses decreased $53 million compared to 2016 which included the termination payment of our Gulf of
Mexico deepwater drilling commitment in 2016.
Exploration expenses increased $86 million during 2017 versus the comparable 2016 period, due primarily to charges
taken as a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our
International E&P segment. In 2017, we recorded non-cash charges of $159 million comprised of $95 million in unproved
property impairments in our International E&P segment and $64 million in dry well costs related to our Diaba License G4-223
in the Republic of Gabon. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon
resulted in an increase to exploration expenses of $43 million during 2017. Unproved property impairments during 2016
primarily consist of non-cash charges related to our decision to not drill our remaining Gulf of Mexico leases.
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,
2017
2016
$
$
246 $
77
25
61
409 $
195
25
5
98
323
Exploration expenses are also discussed in Item 8. Financial Statements and Supplementary Data - Note 10 to the
consolidated financial statements.
Depreciation, depletion and amortization increased $216 million in 2017 from the prior year primarily as a result of an
increase of $176 million in the United States E&P due to a 5% increase in net sales volumes, and an increase in the DD&A
rates within our U.S. resource plays. Also contributing to this higher expense was an increase of $52 million in our
International E&P segment resulting from increased sales volumes due to the completion and start-up of our E.G. Alba field
compression project in mid-2016, and the resumption of sales volumes and production in Libya. Our segments apply the units-
of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an
impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized
costs, can also cause changes to our DD&A. The DD&A rate for United States E&P increased primarily due to the sales volume
mix between our U.S. resource plays, and the outside-operated Gunflint field achieving first production in mid-2016. Also
contributing to the increase was a reduction to the Eagle Ford proved developed reserve base in the fourth quarter of 2016. The
DD&A rate for International E&P remained relatively consistent with the 2016 rate. The following table provides DD&A rates
for each segment.
($ per boe)
DD&A rate
United States E&P
International E&P
2017
2016
$23.51
$6.19
$22.49
$6.21
Impairments increased $162 million in 2017 from the comparable 2016 period. This increase was primarily consisting of
$136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of our
anticipated sales and lower forecasted long-term commodity prices. Additionally, included in proved property impairments was
$89 million in 2017 and $67 million in 2016, both relating to lower forecasted commodity prices in conventional properties in
Oklahoma and the Gulf of Mexico.
34
See Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statement for additional
detail.
Taxes other than income includes 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 increased $32 million in the current
year as a result of increased revenue and sales volumes, and due to a reserve being established for non-income tax examinations
relating to open tax years. The following table summarizes the components of taxes other than income:
(In millions)
Taxes other than income
Production and severance
Ad valorem
Other
Total
Year Ended December 31,
2017
2016
$
$
121 $
13
49
183 $
91
23
37
151
General and administrative expenses decreased $81 million in 2017 primarily due to reduced pension settlement charges
of $32 million in 2017 compared to $103 million in 2016.
Net interest and other decreased $62 million during 2017 primarily as a result of the termination of our forward starting
interest rate swaps, which resulted in a gain of $47 million. Additionally, during 2017 we reduced total long term debt by
approximately $1.75 billion which resulted in a reduction to our net interest and other. The components of net interest and
other are detailed in Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements.
Loss on early extinguishment of debt increased $51 million in 2017 primarily due to make-whole call provisions of $46
million paid upon the redemption of approximately $1.75 billion in senior unsecured notes. See Item 8. Financial Statements
and Supplementary Data - Note 15 to the consolidated financial statements for further detail.
Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 83% and 79% for 2017
and 2016. In 2017, our tax expense was primarily a result of our full valuation allowance on our net federal deferred tax assets
throughout 2017 and the effects of our foreign operations.
See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion
of the effective income tax rate.
Discontinued operations are presented net of tax. See Item 8. Financial Statements and Supplementary Data - Note 5 to
the consolidated financial statements for financial information concerning our discontinued operations.
35
Segment Results: 2017 compared to 2016
Segment income (loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of
income taxes, attributable to the operating segments. A portion of our corporate and operations support general and
administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments,
unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect
comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
(In millions)
United States E&P
International E&P
Segment income (loss)
Items not allocated to segments, net of income taxes (a)
Income (loss) from continuing operations
Income (loss) from discontinued operations (b)
Net income (loss)
Year Ended December 31,
2017
2016
$
$
(148) $
374
226
(1,056)
(830)
(4,893)
(5,723) $
(415)
228
(187)
(1,900)
(2,087)
(53)
(2,140)
(a)
See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for further detail about items not allocated to
segments.
(b)
We sold our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
United States E&P segment loss decreased $267 million in 2017 compared to 2016 primarily due to higher price
realizations and higher sales volumes. Partially offsetting this revenue increase was an increase in DD&A and a decrease in the
income tax benefit, as we did not realize a tax benefit on any net federal deferred tax assets generated in 2017 due to the full
valuation allowance on net federal deferred tax assets in the prior year.
International E&P segment income increased $146 million in 2017 compared to 2016 primarily due to higher price
realizations, and an increase in sales volumes in E.G. and Libya. This was partially offset by an increase in DD&A and income
tax expense as a result of the increase in sales volumes.
36
Consolidated Results of Operations: 2016 compared to 2015
Sales and other operating revenues, including related party are summarized by segment in the following table:
(In millions)
Sales and other operating revenues, including related party
United States E&P
International E&P
Segment sales and other operating revenues, including related party
Unrealized gain on crude oil derivative instruments
Sales and other operating revenues, including related party
Year Ended December 31,
2016
2015
$
$
2,375 $
665
3,040
(110)
2,930 $
3,358
728
4,086
50
4,136
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.
Year Ended
December 31,
Increase (Decrease) Related to
Net Sales
Volumes
Price Realizations
Year Ended
December 31,
2016
2015
$
(In millions)
United States E&P Price-Volume Analysis
Liquid hydrocarbons
Natural gas
Realized gain on crude oil
derivative instruments
Other sales
Total
International E&P Price-Volume Analysis
Liquid hydrocarbons
Natural gas
Other sales
Total
$
$
$
$
2,905
341
78
34
3,358
$
578
108
42
728
(321) $
(32)
(543) $
(35)
(78) $
(25)
46
4
$
$
$
2,041
274
44
16
2,375
546
87
32
665
Marketing revenues decreased $259 million in 2016 from 2015. Marketing activities include the purchase of commodities
from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve
flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can
fluctuate from period to period. The decreases are primarily related to lower marketed volumes in the United States, which
were further compounded by a lower commodity price environment.
Income from equity method investments increased $30 million primarily due to higher net sales volumes in the second
half of 2016 in E.G. as a result of the completion of the Alba field compression project. Additionally, a partial impairment of
our investment in an equity method investee in 2015 of $12 million contributed to the increase in the current year.
Net gain on disposal of assets increased $269 million in 2016 from 2015. See Item 8. Financial Statements and
Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.
Production expenses decreased $267 million in 2016 from 2015. United States E&P declined $238 million primarily due
to lower operational, maintenance and labor costs, coupled with lower net sales volumes resulting from the impact of our non-
core asset dispositions and lower activity levels. International E&P declined $29 million largely due to lower operational and
maintenance costs as well as a more favorable exchange rate on expenses.
The 2016 production expense rate (expense rate per boe) for United States E&P declined primarily due to cost reductions
that occurred at a rate faster than our production decline. The International E&P expense rate decreased in 2016 primarily due
to reduced maintenance and project costs in the U.K. and benefited from the favorable exchange rate. The following table
provides production expense rates for each segment:
37
($ per boe)
Production Expense Rate
United States E&P
International E&P
2016
2015
$5.96
$5.05
$7.38
$5.99
Marketing expenses decreased $255 million in 2016 from the prior year, consistent with the decrease in marketing
revenues discussed above.
Other operating expenses increased $74 million primarily as a result of the termination payment of our Gulf of Mexico
deepwater drilling commitment.
Exploration expenses decreased $648 million in 2016 compared to 2015, reflecting our strategic decision to transition out
of conventional exploration. In 2016, unproved property impairments primarily consisted of non-cash charges related to our
decision to not drill our remaining Gulf of Mexico leases and also included certain other unproved properties in the United
States. In 2015, unproved property impairments are due to changes in our conventional exploration strategy (Gulf of Mexico
and the Harir block in the Kurdistan Region of Iraq), and the sale of certain properties in the Gulf of Mexico, as well as our
unproved property in Colorado.
Dry well costs in 2015 included the operated Solomon exploration well in the Gulf of Mexico and our operated Sodalita
West #1 exploratory well in E.G.
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,
2016
2015
$
$
195 $
25
5
98
323 $
655
212
31
73
971
Exploration expense are also discussed in Item 8. Financial Statements and Supplementary Data - Note 10 to the
consolidated financial statements.
Depreciation, depletion and amortization decreased $565 million in 2016 from the prior year primarily as a result of net
sales volume decreases in the United States E&P segment, including the impact of non-core asset dispositions, and volume
declines due to base declines and lower completion activity. Our segments apply the units-of-production method to the
majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized
costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for
United States E&P decreased primarily due to a higher proved reserve base. The DD&A rate for International E&P declined
primarily due to sales volume mix changes in E.G. and the U.K. for 2016.
($ per boe)
DD&A rate
United States E&P
International E&P
2016
2015
$22.49
$6.21
$24.24
$6.95
Impairments decreased $654 million in 2016 versus 2015. Impairments in 2016 were primarily the result of lower
forecasted commodity prices in conventional properties in Oklahoma and the Gulf of Mexico, and were also the result of
revisions to estimated abandonment costs. Impairments in 2015 included $340 million for the goodwill impairment of the
United States E&P reporting unit, and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico)
as a result of lower forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East
Texas, North Louisiana and Wilburton, Oklahoma.
See Item 8. Financial Statements and Supplementary Data - Note 10 and Note 12 to the consolidated financial statement
for additional detail.
38
Taxes other than income includes production, severance and ad valorem taxes, primarily in the U.S., which tend to
increase or decrease in relation to revenue and sales volumes. The decline in revenue and sales volumes during 2016 resulted in
a decline of $65 million compared to 2015. The following table summarizes the components of taxes other than income:
(In millions)
Taxes other than income
Production and severance
Ad valorem
Other
Total taxes other than income
Year Ended December 31,
2016
2015
$
$
91 $
23
37
151 $
131
39
46
216
General and administrative expenses decreased $107 million primarily due to cost savings realized from the 2015
workforce reductions including corresponding severance expenses.
Net interest and other increased $46 million primarily due to an increase in interest expense as a result of the increase in
long-term debt in the second quarter of 2015. The components of net interest and other are detailed in Item 8. Financial
Statements and Supplementary Data - Note 20 to the consolidated financial statements.
Provision (benefit) for income taxes reflects an effective tax rate of 79% and a benefit of 30% for 2016 and 2015. The
increase in the 2016 effective tax rate was primarily due to the valuation allowance increase of $1,346 million related to our
U.S. benefits on foreign taxes and other federal deferred taxes.
See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion
of the effective income tax rate.
Discontinued operations are presented net of tax. See Item 8. Financial Statements and Supplementary Data - Note 5 to the
consolidated financial statements for financial information concerning our discontinued operations.
Segment Results: 2016 compared to 2015
Segment income (loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of
income taxes, attributable to the operating segments. A portion of our corporate and operations support general and
administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments,
unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect
comparability also are not allocated to operating segments
The following table reconciles segment income (loss) to net income (loss):
(In millions)
United States E&P
International E&P
Segment income (loss)
Items not allocated to segments, net of income taxes (a)
Income (loss) from continuing operations
Income (loss) from discontinued operations (b)
Net income (loss)
(a)
Year Ended December 31,
2016
2015
$
$
(415) $
228
(187)
(1,900)
(2,087)
(53)
(2,140) $
(452)
112
(340)
(1,361)
(1,701)
(503)
(2,204)
See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for further detail about items not allocated to
segments.
(b)
We sold our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
United States E&P segment loss decreased $37 million in 2016 compared to 2015 as a result of lower DD&A expense,
production costs, taxes other than income, and exploration expense, with these expense reductions more than offsetting the
lower revenues as a result of decreases in both price realizations and net sales volumes.
International E&P segment income increased $116 million in 2016 compared to 2015. The increase was largely due to
lower exploration expenses in 2016, as our 2015 expense included costs relating to our transition out of our conventional
exploration program. The remainder of the increase was due to lower production costs and DD&A as a result of lower asset
retirement costs and sales mix, and an increase in income from equity method investments, partially offset by lower price
realizations.
39
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 2017, we experienced an increase in operating cash flows primarily due to improvements in the
commodity price environment which resulted in an increase to consolidated average liquid hydrocarbons price realizations by
over 30% to $42.59. Additionally, we closed on the sale of our Canadian business and other non-core assets resulting in net
proceeds of $1.79 billion, which allowed us to be opportunistic with our high quality acquisitions in the Permian basin. Beyond
the proceeds the non-core asset sales generated, the portfolio changes enhanced our profitability by disposing of higher unit cost
operations and allowing for a more efficient allocation of our Capital Development Program to the higher return opportunities
in the U.S. resource plays.
Steps taken in 2017 to continue our operating cash flow growth include the following actions:
•
Improved cost structure by reducing production expense per boe in 2017.
United States E&P - 7% reduction to $5.57 per boe
International E&P - 14% reduction to $4.33 per boe
• Total 2017 net sales volumes from continuing operations increased 10% compared to 2016.
Other 2017 cash flow highlights include:
• Divested certain non-core assets resulting in net proceeds of $1.79 billion.
• We closed on multiple Permian basin acquisitions for $1.89 billion with cash on hand.
• Through multiple financing transactions we have reduced total debt by approximately $1.75 billion which
will result in a reduction to our future annual interest expense of approximately $115 million.
• Expect to receive $750 million in remaining proceeds from the sale of our Canadian business by March 1,
2018.
• Expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion.
At December 31, 2017, we had approximately $4.0 billion of liquidity consisting of $563 million in cash and cash
equivalents and $3.4 billion available under our revolving credit facility. As previously discussed in our Outlook section, we
are targeting a $2.3 billion Capital Development Program for 2018. We believe our current liquidity level and balance sheet,
along with our non-core asset disposition program and ability to access the capital markets provides us with the flexibility to
fund our business throughout the different commodity price cycles. We will continue to evaluate the commodity price
environment and our spending throughout 2018.
40
Cash Flows
The following table presents sources and uses of cash and cash equivalents from continuing operations for 2017, 2016 and
2015:
(In millions)
Sources of cash and cash equivalents
Operating activities - continuing operations
Disposals of assets, net of cash transferred to the buyer
Common stock issuance
Borrowings
Other
Total sources of cash and cash equivalents
Uses of cash and cash equivalents
Cash additions to property, plant and equipment
Acquisitions, net of cash acquired
Purchases of common stock
Debt repayments
Debt extinguishment costs
Dividends paid
Other
Total uses of cash and cash equivalents
Year Ended December 31,
2017
2016
2015
$
$
$
$
1,988
1,787
—
988
68
4,831
$
$
(1,974) $
(1,891)
(11)
(2,764)
(46)
(170)
(30)
(6,886) $
901
1,219
1,236
—
56
3,412
$
$
(1,204) $
(902)
(6)
(1)
—
(162)
(4)
(2,279) $
1,537
225
—
1,996
101
3,859
(3,485)
—
(11)
(1,069)
—
(460)
(8)
(5,033)
Cash flows generated from operating activities in 2017 were higher as commodity prices and price realizations improved
compared to 2016. This increase in price realization coupled with our increased sales volumes and continued focus on cost
reductions resulted in an increase to cash flows generated from operating activities.
Proceeds from the disposals of assets for 2017 are primarily a result of the disposal of our Canadian business, and proceeds
from disposals of assets in 2016 are primarily from the sale of our Wyoming upstream and midstream assets, as well as the sale
of certain other non-operated CO2 and waterflood assets in West Texas and New Mexico. Disposals of assets in 2015 pertain to
the sale of certain of our operated and non-operated producing properties in the Gulf of Mexico as well as natural gas assets in
East Texas, North Louisiana and Wilburton, Oklahoma. Disposition transactions are discussed in further detail in Item 8.
Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements.
Issuance of common stock reflects net proceeds received in March 2016 from our public sale of common stock. See Item
8. Financial Statements and Supplementary Data - Note 22 to the consolidated financial statements for additional information.
Borrowings in 2017 are a result of the issuance of $1 billion of 4.4% senior unsecured notes due in 2027. Our 2015
borrowings reflect net proceeds received from the issuance of senior notes in June 2015. Financing transactions are discussed
in further detail in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for
additional information.
Additions to property, plant and equipment reflect a significant use of cash and cash equivalents. The following table
shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and
equipment as presented in the consolidated statements of cash flows for 2017, 2016 and 2015:
(In millions)
United States E&P
International E&P
Corporate
Total capital expenditures
Change in capital expenditure accrual
Additions to property, plant and equipment
Year Ended December 31,
2016
2015
2017
$
$
2,081
42
27
2,150
(176)
1,974
$
$
936
82
18
1,036
168
1,204
$
$
2,553
368
25
2,946
539
3,485
During 2017, we closed on multiple Permian basin acquisitions for approximately $1.9 billion with cash on hand.
Additionally, during 2016, we closed the Oklahoma STACK acquisition for a purchase price of $902 million, net of cash
41
acquired; see Item 8. Financial Statements and Supplementary Data – Note 4 to the consolidated financial statements for further
information concerning acquisitions.
In December 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction.
Additionally, during the third quarter of 2017, we used the net proceeds of the borrowing disclosed above plus existing cash on
hand to redeem $1.76 billion in senior unsecured notes resulting in a recognized loss on early extinguishment of debt of $46
million, primarily due to make-whole call provisions. In November 2015, we repaid our $1 billion 0.90% senior notes upon
maturity. Financing transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note
15 to the consolidated financial statements for additional information.
During 2017, the Board of Directors approved a $0.05 per share quarterly dividend. See Capital Requirements below for
additional information about the fourth quarter dividend. During 2015 we announced an adjustment to our quarterly dividend
starting in third quarter 2015, with the full-year impact resulting in a decrease of dividends paid in 2017 and 2016.
Liquidity and Capital Resources
In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020, to May 28, 2021. In July 2017, we
increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of
each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension.
We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an
additional $107 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of
credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.
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, 2017, we had approximately $4.0
billion of liquidity consisting of $563 million in cash and cash equivalents and $3.4 billion available under our revolving credit
facility. During the first quarter of 2018, we expect to receive $750 million in remaining proceeds from the sale of our
Canadian business. Our working capital requirements are supported by these sources and 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 could affect our operations and
our ability to access the capital markets. Our corporate credit ratings as of December 31, 2017 are: Standard & Poor's Ratings
Services BBB- (stable); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (stable). A downgrade in our
credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral
requirements. See Item 1A. Risk Factors for a discussion of how a downgrade in our credit ratings could affect us.
In December of 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction
that preserved our ability to remarket up to $1 billion of tax-exempt municipal bonds prior to 2037. 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
At December 31, 2017, we had no borrowings against our revolving credit facility.
At December 31, 2017, we had $5.5 billion in long-term debt outstanding, with our next debt maturity in the amount of
$600 million due in 2020.
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.
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
Asset Disposals
We closed on $1.8 billion of non-core asset sales during 2017, with the largest transaction being the disposal of our
Canadian business. During the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in
our International E&P segment for combined proceeds of $53 million, before closing adjustments. We have closed on one of
these agreements in 2017, and we expect the remainder of the agreements to close during 2018.
See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional
discussion of these dispositions.
Debt-To-Capital Ratio
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the
last day of each fiscal quarter. Our debt-to-capital ratio was 32% at December 31, 2017 and 29% at December 31, 2016.
(Dollars in millions)
Long-term debt due within one year
Long-term debt
Total debt
Equity
Calculation
Total debt
Total debt plus equity (total capitalization)
Debt-to-capital ratio
Capital Requirements
Capital Spending
2017
2016
$
$
$
$
$
— $
5,494
5,494
11,708
5,494
17,202
$
$
$
$
686
6,581
7,267
17,541
7,267
24,808
32%
29%
Our approved Capital Development Program for 2018 is $2.3 billion. Additional details were previously discussed in
Outlook.
Share Repurchase Program
The remaining share repurchase authorization as of December 31, 2017 is $1.5 billion.
Other Expected Cash Outflows
On January 30, 2018, our Board of Directors approved a dividend of $0.05 per share for the fourth quarter of 2017. The
dividend is payable on March 12, 2018 to shareholders on record on February 21, 2018.
We plan to make contributions of up to $65 million to our funded pension plans during 2018. Cash contributions to be paid
from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $21
million in 2018.
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, 2017.
(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
Drilling rigs and fracturing crews(d)
Other
Total purchase obligations
Other long-term liabilities reported in the
consolidated balance sheet(e)
Total contractual cash obligations(f)
Total
2018
$
$
8,776
119
108
115
1,581
21
42
1,867
256
29
94
65
313
21
13
506
2019-
2020
2021-
2022
Later
Years
$
$
1,103
55
$
1,512
31
5,905
4
8
48
483
—
24
563
4
2
241
—
5
252
2
—
544
—
—
546
205
486
6,660
11,248
Includes anticipated cash payments for interest of $256 million for 2018, $503 million for 2019-2020, $477 million for 2021-2022 and $2,003 million for
the remaining years for a total of $3,239 million.
63
1,858
77
1,798
141
932
$
$
$
$
$
(a)
(b) Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to
(c)
(d)
(e)
(f)
contractually obligated exploratory work programs that are expensed immediately.
Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31, 2017 our
minimum commitment would be $14 million.
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 $1,483
million. See Item 8. Financial Statements and Supplementary Data – Note 11 to the consolidated financial statements.
Transactions with Related Parties
We own a 63% working interest in the Alba field offshore E.G. 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, 2017, 2016 and 2015 aggregated $89 million, $166 million and $53 million. Most of the letters of credit are in
support of obligations recorded in the consolidated balance sheet. For example, they are issued to counterparties to support
firm transportation agreements and future abandonment liabilities.
44
Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies
We have incurred and may continue to incur substantial 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 reflected in 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.
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. 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 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, seismic 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. 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, production history and continual reassessment of the viability of
production 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 2017 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)
SEC Pricing 2017
$
$
$
$
51.34
2.98
54.39
22.03
When determining the December 31, 2017 proved reserves for each property, the benchmark prices listed above were
adjusted using price differentials that account for property-specific quality and location differences.
Estimates of future cash flows associated with proved reserves are based on actual costs of developing and producing
proved reserves at the end of the year. If commodity prices were to decrease by approximately 10%, below average prices used
to estimate 2017 proved reserves (see table above), we would not expect price related reserve revisions to have a material
impact on proved reserve volumes. 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 2017 proved reserves
based on 2017 production.
Impact of a 10% Increase in Proved
Reserves
Impact of a 10% Decrease in
Proved Reserves
(In millions, except per boe)
United States E&P
International E&P
Asset Retirement Obligations
DD&A per boe
$
$
(2.14) $
(0.56) $
Pretax Income
183
30
DD&A per boe
2.61
$
0.69
$
Pretax Income
$
$
(224)
(36)
We have material legal, regulatory and contractual obligations to remove and dismantle long-lived assets and to restore
land or seabed at the end of oil and gas production operations. A liability equal to the fair value of such obligations and a
corresponding capitalized asset retirement cost are recognized on the balance sheet in the period in which the legal obligation is
incurred and a reasonable estimate of fair value can be made. The capitalized asset retirement cost is depreciated using the
units-of-production method or the straight line method (dependent on the underlying asset) and the discounted liability is
accreted over the period until the obligation is satisfied, the impacts of which are recognized as DD&A in the consolidated
statements of income. In many cases, the satisfaction and subsequent discharge of these liabilities is projected to occur many
years, or even decades, into the future. Furthermore, the legal, regulatory and contractual requirements often do not provide
specific guidance regarding removal practices and the criteria that must be fulfilled when the removal and/or restoration event
actually occurs.
Estimates of retirement costs are developed for each property based on numerous factors, such as the scope of the
dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and
processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for
equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering
professionals. Inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the
obligations. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is
revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income
statement, as appropriate. Changes in estimated asset retirement obligations for late life assets could result in future impairment
charges or in the recognition of income. See Item 8. Financial Statements and Supplementary Data – Note 11 to the
consolidated financial statements for disclosures regarding our asset retirement obligation estimates.
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 obligations that must be assessed, the number of underlying assumptions and the wide range of
possible assumptions.
46
Fair Value Estimates
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.
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 14 to
the consolidated financial statements for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
•
•
•
impairment assessments of long-lived assets;
impairment assessments of goodwill; and
recorded value of derivative instruments.
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 Development Program, 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. During 2017 lower forecasted long-term commodity prices and the anticipated sales of certain non-
core proved properties in our International E&P segment triggered an assessment of certain of our long-lived assets related to
oil and gas producing properties for impairment. We estimated the fair values using an income and market approach and
recognized impairments. As of December 31, 2017 our estimated undiscounted cash flows relating to our remaining long-lived
assets significantly exceeded their carrying values. Long-lived assets most at risk for future impairment had estimated
undiscounted cash flows that exceeded their $66 million carrying value by $22 million. See Item 8. Financial Statements and
Supplementary Data Note 10 and Note 14 to the consolidated financial statements for discussion of impairments recorded in
2017, 2016 and 2015 and the related fair value measurements.
47
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 development 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.
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.
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 of a reporting unit with goodwill 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 only International
E&P includes goodwill. We performed our annual impairment test in the second quarter of 2017 for the International E&P
reporting unit and no impairment was required. As of the date of our last goodwill impairment assessment, our International
E&P reporting unit fair value exceeded its book value by over 40%.
We estimate the fair values of our International E&P reporting unit using a combination of market and income approaches.
Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. 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 our peers from the investor analyst community. The income approach
utilizes discounted cash flows, which are based on forecasted assumptions. Key assumptions to the income approach are the
same as those described above regarding our impairment assessment of long lived assets and are consistent with those that
management uses to make business decisions. We believe the estimates and assumptions used in our impairment assessments
are reasonable and based on available market information, but variations in such assumptions could result in materially different
calculations of fair value and determinations of whether or not an impairment is indicated. See Item 8. Financial Statements
and Supplementary Data Note 12 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 13 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.
48
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.
On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Reform Legislation"), which made
significant changes to U.S. federal income tax law. We expect that certain aspects of the Tax Reform Legislation will positively
impact our future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate. The Tax Reform
Legislation is a comprehensive bill containing several other provisions, such as limitations on the deductibility of interest
expense and certain executive compensation, that are not expected to have a material effect on our results. The ultimate impact
of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as
well as additional regulatory guidance that may be issued. Item 8. Financial Statements and Supplementary Data – Note 7 to
the consolidated financial statements for further disclosure regarding Tax Reform Legislation.
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
evidence includes losses in recent years as well as the forecasts of future income (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, 2017, we reflect a valuation allowance in
our Consolidated Balance Sheet of $926 million against our gross deferred tax assets of $2.0 billion in various jurisdictions in
which we operate. Our gross deferred tax assets consist primarily of federal U.S. operating loss carryforwards of $898 million,
which will expire in 2035, 2036 and 2037. 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 is 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.
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;
the rate of future increases in compensation levels; and
health care cost projections.
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
49
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 $250 million par value outstanding. The constructed yield curve is based on those bonds representing
the 50% highest yielding issuances within each defined maturity group.
Of the assumptions used to measure obligations and estimated annual net periodic benefit cost as of December 31, the
discount rate has the most significant effect on the periodic benefit cost reported for the plans. The hypothetical impacts of a
0.25% change in the discount rates of 3.55% for our U.S. pension plans and 3.54% for our other U.S. postretirement benefit
plans is summarized in the table below:
(In millions)
Impact of a 0.25% Increase in
Discount Rate
Impact of a 0.25% Decrease in
Discount Rate
Obligation
Expense
Obligation
Expense
U.S. pension plans
Other U.S. postretirement benefit plans
$
$
(4) $
(5) $
— $
— $
4
5
$
$
—
—
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. Decreasing the 6.50%
asset rate of return assumption by 0.25% would not have a significant impact on our defined benefit pension expense.
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 17 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
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. 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.
50
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 and foreign currency exchange 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 – Notes 13 and 14 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 2017 and 2016 were impacted by crude oil and natural gas derivatives related to a portion of our
forecasted United States E&P sales. The table below provides a summary of open positions as of December 31, 2017 and the
weighted average price for those contracts:
Three-Way Collars (a)
Volume (Bbls/day)
Weighted average price per Bbl:
Ceiling
Floor
Sold put
Swaps
Volume (Bbls/day)
Weighted average price per Bbl
Basis Swaps (b)
Volume (Bbls/day)
Weighted average price per Bbl
Crude Oil
2018
2019
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
First
Quarter
Second
Quarter
85,000
85,000
85,000
85,000
10,000
10,000
$56.38
$51.65
$45.00
$56.38
$51.65
$45.00
$56.96
$51.53
$44.65
20,000
$55.12
20,000
$55.12
—
$—
$56.96
$51.53
$44.65
—
$—
5,000
$(0.60)
5,000
$(0.60)
10,000
$(0.67)
10,000
$(0.67)
$60.00
$55.00
$47.00
$60.00
$55.00
$47.00
—
$—
—
$—
—
$—
—
$—
(a)
(b)
Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling
price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average
ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.
The basis differential price is between WTI Midland and WTI Cushing.
51
Three-Way Collars
Volume (MMBtu/day)
Weighted average price per MMBtu
Ceiling
Floor
Sold put
Natural Gas
2018
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
200,000
160,000
160,000
160,000
$3.79
$3.08
$2.55
$3.61
$3.00
$2.50
$3.61
$3.00
$2.50
$3.61
$3.00
$2.50
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a
hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of
December 31, 2017:
(In millions)
Crude oil derivatives
Natural gas derivatives
Total
Interest Rate Risk
Hypothetical Price
Increase of 10%
Hypothetical Price
Decrease of 10%
$
$
(180) $
(8)
(188) $
149
7
156
At December 31, 2017, our portfolio of long-term debt was substantially comprised of fixed rate instruments. 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. Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on our financial
assets and liabilities as of December 31, 2017, is provided in the following table.
(In millions)
Financial assets (liabilities): (a)
Fair Value
Hypothetical
Price Increase of
10%
Hypothetical
Price Decrease of
10%
Long-term debt, including amounts due within one year
$
(5,976) (b)(c) $
190 $
(202)
(a)
(b)
(c)
Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to
changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
Excludes capital leases.
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices fall below
current 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.
52
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
54
54
55
57
58
59
60
61
62
100
101
53
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
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, 2017.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2017 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
President and Chief Executive Officer
/s/ Dane E. Whitehead
Executive Vice President and Chief Financial Officer
54
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 sheets of Marathon Oil Corporation and its subsidiaries as of
December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, cash flows and
stockholders’ equity for each of the three years in the period ended December 31, 2017, 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, 2017, 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, 2017 and 2016, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2017 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, 2017, 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.
55
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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2018
We have served as the Company’s auditor since 1982.
56
MARATHON OIL CORPORATION
Consolidated Statements of Income
(In millions, except per share data)
Revenues and other income:
Sales and other operating revenues, including related party
Marketing revenues
Income from equity method investments
Net gain (loss) on disposal of assets
Other income
Total revenues and other income
Costs and expenses:
Production
Marketing, including purchases from related parties
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
Loss on early extinguishment of debt
Income (loss) from continuing operations before income taxes
Provision (benefit) for income taxes
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Per Share Data
Basic:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Diluted:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Dividends
Weighted average shares:
Basic
Diluted
$
$
$
$
$
$
$
$
$
Year Ended December 31,
2016
2015
2017
$
4,211
162
256
58
78
4,765
706
168
431
409
2,372
229
183
400
4,898
(133)
(270)
(51)
(454)
376
(830)
(4,893)
(5,723) $
(0.97) $
(5.76) $
(6.73) $
(0.97) $
(5.76) $
(6.73) $
$
0.20
850
850
$
2,930
240
175
389
53
3,787
712
245
484
323
2,156
67
151
481
4,619
(832)
(332)
—
(1,164)
923
(2,087)
(53)
(2,140) $
(2.55) $
(0.06) $
(2.61) $
(2.55) $
(0.06) $
(2.61) $
$
0.20
819
819
4,136
499
145
120
53
4,953
979
500
410
971
2,721
721
216
588
7,106
(2,153)
(286)
—
(2,439)
(738)
(1,701)
(503)
(2,204)
(2.51)
(0.75)
(3.26)
(2.51)
(0.75)
(3.26)
0.68
677
677
The accompanying notes are an integral part of these consolidated financial statements.
57
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income
(In millions)
Net income (loss)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other
Income tax provision (benefit)
Postretirement and postemployment plans, net of tax
Derivative hedges
Net unrecognized gain (loss)
Reclassification of gains on terminated derivative hedges
Income tax provision (benefit)
Derivative hedges, net of tax
Foreign currency hedges
Net recognized loss reclassified to discontinued operations
Income tax provision (benefit)
Foreign currency hedges, net of tax
Other, net of tax
Other comprehensive income (loss)
Comprehensive income (loss)
Year Ended December 31,
2017
2016
2015
$
(5,723) $
(2,140) $
(2,204)
21
7
28
(13)
(47)
21
(39)
16
(4)
12
61
—
(22)
39
34
(4)
30
2
21
(5,702) $
—
—
—
1
52
(2,088) $
$
228
(86)
142
—
—
—
—
—
—
—
—
142
(2,062)
The accompanying notes are an integral part of these consolidated financial statements.
58
MARATHON OIL CORPORATION
Consolidated Balance Sheets
(In millions, except par values and share amounts)
Assets
Current assets:
Cash and cash equivalents
Receivables, less reserve of $12 and $6
Notes receivable
Inventories
Other current assets
Current assets held for sale
Total current assets
Equity method investments
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,564 and $20,255
Goodwill
Other noncurrent assets
Noncurrent assets held for sale
Total assets
Liabilities
Current liabilities:
Accounts payable
Payroll and benefits payable
Accrued taxes
Other current liabilities
Long-term debt due within one year
Current liabilities held for sale
Total current liabilities
Long-term debt
Deferred tax liabilities
Defined benefit postretirement plan obligations
Asset retirement obligations
Deferred credits and other liabilities
Noncurrent liabilities held for sale
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 and 937 million shares, respectively (par value $1 per share, 1.1
billion shares authorized)
Held in treasury, at cost – 87 million and 90 million shares
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss
Total stockholders' equity
Total liabilities and stockholders' equity
The accompanying notes are an integral part of these consolidated financial statements.
59
December 31,
2017
2016
$
$
$
563
1,082
748
126
36
11
2,566
847
17,665
115
764
55
22,012
1,395
108
177
288
—
—
1,968
5,494
833
362
1,428
217
2
10,304
2,488
748
—
136
66
227
3,665
931
16,727
115
558
9,098
31,094
967
129
94
243
686
121
2,240
6,581
769
345
1,602
225
1,791
13,553
—
—
937
(3,325)
7,379
6,779
(62)
11,708
22,012
$
937
(3,431)
7,446
12,672
(83)
17,541
31,094
$
$
$
$
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows
(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:
Year Ended December 31,
2015
2016
2017
$ (5,723) $ (2,140) $ (2,204)
Discontinued operations
Depreciation, depletion and amortization
Impairments
Exploratory dry well costs and unproved property impairments
Net (gain) loss on disposal of assets
Deferred income taxes
Net (gain) loss on derivative instruments
Net cash received (paid) in settlement of derivative instruments
Stock based compensation
Equity method investments, net
Changes in:
Current receivables
Inventories
Current accounts payable and accrued liabilities
All other operating, net
Net cash provided by operating activities from continuing operations
Investing activities:
Additions to property, plant and equipment
Acquisitions, net of cash acquired
Disposal of assets, net of cash transferred to the buyer
Equity method investments - return of capital
Purchases of short term investments
Maturities of short term investments
All other investing, net
Net cash used in investing activities from continuing operations
Financing activities:
Borrowings
Debt repayments
Debt extinguishment costs
Common stock issuance
Purchases of common stock
Dividends paid
All other financing, net
Net cash provided by (used in) financing activities
Cash Flow from Discontinued Operations:
Operating activities
Investing activities
Changes in cash included in current assets held for sale
Net increase in cash and cash equivalents of discontinued operations
Effect of exchange rate changes 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 at end of period
The accompanying notes are an integral part of these consolidated financial statements.
60
4,893
2,372
229
323
(58)
(61)
(11)
98
50
20
(334)
10
297
(117)
1,988
(1,974)
(1,891)
1,787
64
—
—
(30)
(2,044)
988
(2,764)
(46)
—
(11)
(170)
—
(2,003)
141
(13)
2
130
4
(1,925)
2,488
563
$
53
2,156
67
220
(389)
828
63
61
48
17
67
64
(137)
(77)
901
(1,204)
(902)
1,219
55
—
—
(1)
(833)
—
(1)
—
1,236
(6)
(162)
1
1,068
177
(41)
100
236
(3)
1,369
1,119
2,488
$
503
2,721
721
867
(120)
(804)
(126)
55
45
33
790
25
(906)
(63)
1,537
(3,485)
—
225
77
(925)
925
24
(3,159)
1,996
(1,069)
—
—
(11)
(460)
(5)
451
39
(43)
90
86
(3)
(1,088)
2,207
1,119
$
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
Loss
Total
Equity
December 31, 2014 Balance
$
— $
770
$
(3,642) $
6,531
$
17,638
$
(277) $
21,020
December 31, 2016 Balance
$
— $
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net loss
Other comprehensive loss
Dividends paid
December 31, 2015 Balance
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net loss
Other comprehensive income
Dividends paid
Common stock issuance
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net loss
Other comprehensive income
Dividends paid
Common stock issuance
December 31, 2017 Balance
(Shares in millions)
December 31, 2014 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2015 Balance
Shares issued - stock-based
compensation
Shares repurchased
Common stock issuance
December 31, 2016 Balance
Shares issued - stock-based
compensation
Shares repurchased
Common stock issuance
December 31, 2017 Balance
—
—
—
—
—
—
—
—
—
—
—
—
96
(8)
—
—
—
—
(32)
—
(1)
—
—
—
—
—
—
(2,204)
—
(460)
—
—
—
—
142
—
64
(8)
(1)
(2,204)
142
(460)
$
— $
770
$
(3,554) $
6,498
$
14,974
$
(135) $
18,553
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
167
937
—
—
—
—
—
—
—
128
(5)
—
—
—
—
—
(86)
—
(35)
—
—
—
1,069
—
—
—
(2,140)
—
(162)
—
—
—
—
—
52
—
—
$
(3,431) $
7,446
$
12,672
$
(83) $
117
(11)
—
—
—
—
—
(50)
—
(17)
—
—
—
—
—
—
—
(5,723)
—
(170)
—
—
—
—
—
21
—
—
42
(5)
(35)
(2,140)
52
(162)
1,236
17,541
67
(11)
(17)
(5,723)
21
(170)
—
$
— $
937
$
(3,325) $
7,379
$
6,779
$
(62) $
11,708
Preferred
Stock
Common
Stock
Treasury
Stock
—
—
—
—
—
—
—
—
—
—
—
—
770
—
—
770
—
—
167
937
—
—
—
937
95
(2)
—
93
(3)
—
—
90
(3)
—
—
87
The accompanying notes are an integral part of these consolidated financial statements.
61
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
1. Summary of Principal Accounting Policies
We are a global energy 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 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 revenue 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. Differences in the
basis of the investments and the separate net asset value of the investees, if any, are amortized into income over the remaining
useful lives of the underlying assets, except for the excess related to goodwill.
Reclassifications – We have reclassified certain prior year amounts between operating cash flow categories to present it on
a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.
Discontinued operations – As a result of the sale of our Canadian business in 2017, we reflected this business as
discontinued operations in all periods presented. Disclosures in this report related to results of operations and cash flows are
presented on the basis of continuing operations unless otherwise stated. Assets and liabilities are presented as held for sale in
the historical periods in the consolidated balance sheets. See Note 5 for discussion of the divestiture in further detail.
As discussed above we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and
exploration stage in-situ leases in the second quarter 2017. The characteristics and composition of our North America E&P
reporting segment remained unchanged and there was no effect on previously reported segment information. As all our
remaining properties within the segment are located within the United States, we concluded that our North America E&P
segment would be renamed United States E&P segment, effective June 30, 2017. During the year, no changes occurred to our
International E&P segment. See Note 6 for further information on our reportable segments.
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 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 are recognized when products are shipped or services are provided to customers, title is
transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of
62
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves
were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.
In the lower 48 states of the U.S., production volumes of crude oil and condensate, NGLs and natural gas are generally sold
immediately and transported to market. In international locations, liquid hydrocarbon production volumes 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.
Short-term Investments - Our short-term investments are comprised of bank time deposits with original maturities of
greater than three months but less than twelve months. They are classified as held-to-maturity investments, which are recorded
at amortized cost.
Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from
purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the 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.
Notes receivable - We hold two notes receivable from the sale of our Canadian business, which closed in the second
quarter of 2017. Both notes receivable were initially recorded at fair value and are reported at amortized cost. The notes
receivable are evaluated for collectability on an individual basis each reporting period, based on the financial condition of the
debtor. No allowances for credit losses were established for the notes receivable as of December 31, 2017. See Note 5 for
additional discussion.
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, foreign currency 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, foreign
currency 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 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 effective
portion of changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the
hedged item is reclassified to net income when the underlying forecasted transaction is recognized in net income. Ineffective
portions of a cash flow hedge’s change in fair value are recognized currently within net interest and other on the consolidated
statements of income. However, if it is determined that the likelihood of the original forecasted transaction occurring is no
longer probable, the entire accumulated gain or loss recognized in other comprehensive income is immediately reclassified into
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 and natural gas that we produce.
Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
63
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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. If significant transfers occur, they would be disclosed in Note 14 to the consolidated financial statements.
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.
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 as summarized below.
Type of Asset
Office furniture, equipment and computer hardware
Pipelines
Plants, facilities and infrastructure
Range of Useful Lives
4 to 15 years
10 to 40 years
3 to 40 years
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 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.
64
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include
the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.
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 and
seabed, including those leased. Estimates of these costs are developed for each property based on the type of production
facilities and equipment, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment,
currently available procedures and consultations with construction and engineering professionals.
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 and common stock units is determined based on the market value of our
common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted
stock awards are granted.
The fair value of our 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.
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.
During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining
to share-based payment transactions. As a result of this adoption, all cash payments for withheld shares made to taxing
authorities on the employees' behalf are presented within the financing activities section instead of the operating activities
section of the statement of cash flows. We elected the retrospective method for adoption of this update and the change in the
statement of cash flows is not material for the years ended December 31, 2016 or 2015. Excess tax benefits were classified as
an operating activity within the statement of cash flows on a prospective basis beginning in 2017; as such, prior periods were
not adjusted. See Note 2 for additional discussion.
65
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
2. Accounting Standards
Not Yet Adopted
In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements.
This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an
amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.
Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not
previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for
us in the first quarter of 2018 and shall be applied retrospectively to each prior reporting period presented (“full retrospective
method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified
retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method.
The adoption of this ASU will not have a material impact on our consolidated results of operations, financial position or cash
flows. However, as a result of this standard we will change our presentation of marketing revenues and marketing expenses
from the current gross presentation to a net presentation for a portion of our international contracts. For the years ended
December 31, 2017 and 2016, we expect the impact of this change to be a reduction of approximately $130 million and $100
million, respectively, in marketing revenue and expenses in our consolidated results of operations. We will provide the
disclosures required by this standard, such as key sources of revenues from transactions with customers, disaggregated revenue
information, and significant accounting estimates and judgments, beginning in the first quarter of 2018.
In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined
pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will
present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee
compensation costs arising from services rendered during the period. Only the service cost component will be eligible for
capitalization in assets. We will adopt this standard in the first quarter of 2018 on a retrospective basis, and will reclassify
certain amounts from general and administrative expense to the exploration, production and our new other net periodic benefit
costs expense categories on our consolidated statements of income.
In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in
practice in how certain transactions are classified in the statement of cash flows. We will adopt this standard during the first
quarter of 2018 on a retrospective basis with no significant impact on our consolidated results of operations, financial position
or cash flows.
In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the
total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present
transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents,
and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the
totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on
the face of the statement of cash flows or in the notes to the financial statements. We will adopt this standard in the first quarter
of 2018 on a retrospective basis and do not expect the adoption of this standard to have a significant impact on our consolidated
results of operations, financial position or cash flows.
In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer
of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies
that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with
customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10.
We will adopt this standard in the first quarter of 2018 using the modified retrospective approach with no material impact on
our consolidated results of operations, financial position or cash flows.
In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist
entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to
evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group
of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also
requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it
with how outputs are described in the new revenue guidance. We will adopt this standard in the first quarter of 2018 on a
prospective basis. Since we adopted the standard on a prospective basis, adoption of this standard will not have a significant
impact on our consolidated results of operations, financial position or cash flows for prior periods.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition,
measurement, presentation, and disclosure of financial instruments. We plan to adopt this standard in the first quarter of 2018
66
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial
position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases,
including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being
accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals,
oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and
rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019
and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial
statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption
date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our
consolidated results of operations, financial position or cash flows.
In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable
entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the
overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first
quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective
adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this
accounting standards update, including transition requirements, and are assessing the impact it may have on our results of
operations, financial position, or cash flows.
In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the
implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill
impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s
carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is
effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim
or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a
prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for
prior periods.
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. The standard requires the use of a forward-
looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in the first
quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained
earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the
provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of
operations, financial position or cash flows.
Recently Adopted
In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-
based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax
expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the
statement of cash flows. This standard was effective for us in the first quarter of 2017. The new standard requires a company to
make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same
methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our
financial statements.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable
value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in the
first quarter of 2017, and was applied prospectively. Adoption of this standard did not have a significant impact on our
consolidated results of operations, financial position or cash flows.
67
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
3.
Income (Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income
per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below
exclude 11 million, 13 million and 13 million stock options in 2017, 2016 and 2015 that were antidilutive.
(In millions, except per share data)
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Weighted average common shares outstanding
Per basic share:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
Per diluted share:
Income (loss) from continuing operations
Income (loss) from discontinued operations
Net income (loss)
4. Acquisitions
2017 - United States E&P
Year Ended December 31,
2016
2015
2017
$
$
$
$
$
$
$
$
(830) $
(4,893)
(5,723) $
(2,087) $
(53)
(2,140) $
850
819
(0.97) $
(5.76) $
(6.73) $
(0.97) $
(5.76) $
(6.73) $
(2.55) $
(0.06) $
(2.61) $
(2.55) $
(0.06) $
(2.61) $
(1,701)
(503)
(2,204)
677
(2.51)
(0.75)
(3.26)
(2.51)
(0.75)
(3.26)
In the fourth quarter of 2017, we closed on our acquisition of additional acreage in the Northern Delaware basin of New
Mexico from a private seller for $63 million in cash, subject to post-closing adjustments. We accounted for this transaction as
an asset acquisition, allocating the purchase price to unproved property within property, plant and equipment.
In the second quarter of 2017, we closed on our acquisitions of approximately 91,000 net acres in the Permian basin,
including over 70,000 net acres in the Northern Delaware basin of New Mexico. On May 1, 2017, we closed on our acquisition
with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately
70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017,
we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash,
subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these
acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the
purchase price allocated to unproved property within property, plant and equipment.
2016 - United States E&P
On August 1, 2016, we closed on our acquisition of PayRock Energy Holdings, LLC (“PayRock”), a portfolio company of
EnCap Investments, including approximately 61,000 net surface acres in the oil window of the Anadarko Basin STACK play in
Oklahoma. The purchase price of $904 million, subject to closing adjustments, was paid with cash on hand. We accounted for
this transaction as an asset acquisition, with a majority of the purchase price allocated to unproved property within property,
plant and equipment.
68
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
5. Dispositions
Oil Sands Mining Segment
On May 31, 2017 we closed on the sale of our Canadian business, which included our 20% non-operated interest in the
AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the
terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of
2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million. We
recorded these notes receivable at fair value, see Note 14 for fair value measurements. Our notes receivable are with 10084751
Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is
guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first
quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant
and equipment of our Canadian business. As the effective date of the transaction was January 1, 2017, we recorded a loss on
sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business
that were recorded in our financial statements but transferred to the buyer upon closing.
Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the
consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our
consolidated statements of income as discontinued operations:
(In millions)
Total sales and other revenues and other income
Net gain (loss) on disposal of assets
Total revenues and other income
Costs and expenses:
Production expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Other
Total costs and expenses
Pretax income (loss) from discontinued operations
Provision (benefit) for income taxes
Income (loss) from discontinued operations
Year Ended December 31,
2017
2016
2015
431
(43)
388
254
—
40
6,636
25
$
863
$
—
863
601
7
239
—
87
908
—
908
715
347
236
31
98
6,955
(6,567)
(1,674)
(4,893) $
934
(71)
(18)
(53) $
1,427
(519)
(16)
(503)
$
$
69
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business
reported as discontinued operations and other non-core international assets and liabilities from continuing operations, that are
reflected as held for sale on our consolidated balance sheets at December 31, 2017 and December 31, 2016:
(In millions)
Assets held for sale
Current assets:
Cash and cash equivalents
Accounts receivables
Inventories
Other
Total current assets held for sale—discontinued operations
Total current assets held for sale—continuing operations
Total current assets held for sale
Noncurrent assets:
Property, plant and equipment, net
Other
Total noncurrent assets held for sale—discontinued operations
Total noncurrent assets held for sale—continuing operations
Total noncurrent assets held for sale
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable
Other
Total current liabilities held for sale—discontinued operations
Total current liabilities held for sale—continuing operations
Total current liabilities held for sale
Noncurrent liabilities:
Asset retirement obligations
Deferred tax liabilities
Other
Total noncurrent liabilities held for sale—discontinued operations
Total noncurrent liabilities held for sale—continuing operations
Total noncurrent liabilities held for sale
United States E&P Segment
December 31,
December 31,
2017
2016
$
$
$
$
$
$
$
$
— $
—
—
—
—
11
11
$
— $
—
—
55
55
$
— $
—
—
—
— $
— $
—
—
—
2
2
$
2
129
91
4
226
1
227
8,991
106
9,097
1
9,098
111
10
121
—
121
95
1,669
20
1,784
7
1,791
As disclosed above, we closed on the sale of our Canadian business in May of 2017. This sale included interests in our
exploration stage in-situ leases which were included within our historically named North America E&P Segment. See Note 6
for further detail on our segments. These interests have been reflected as discontinued operations and are included within the
disclosure above.
In July 2017, we entered into an agreement to sell certain conventional assets in Oklahoma. We closed on the sale in
September 2017 for proceeds of $25 million, and recognized a pre-tax gain of $21 million.
In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas
and New Mexico. The sale closed in late October for proceeds of $235 million, and we recognized a total pre-tax gain of $63
70
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
million. During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to
multiple purchasers for combined proceeds of approximately $67 million, and recognized a total pre-tax gain of $55 million.
In April 2016, we announced the sale of our Wyoming upstream and midstream assets. During the second quarter, we
received proceeds of approximately $690 million and recorded a pre-tax gain of $266 million with the remaining asset sales
closing in November 2016 for proceeds of $155 million, excluding closing adjustments. A pre-tax gain of $38 million was
recognized in the fourth quarter 2016.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated
Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain
undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds. We closed on certain of the
asset sales and recognized a net pre-tax loss on sale of $48 million in 2016, the remaining asset closed in 2017 with a net pre-
tax gain on sale of $32 million.
In November 2015, we entered into an agreement to sell 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. The transaction closed in
December 2015, excluding the Neptune field, for proceeds of $111 million. A $228 million pretax gain was recorded in the
fourth quarter of 2015. The Neptune field transaction closed during the first quarter of 2016 for cash proceeds of $4 million.
In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for
proceeds of $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash
impairment charge of $44 million related to these assets (see Note 14).
International E&P Segment
In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International
E&P segment for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the
second half of 2017 and recognized no net pre-tax gain or loss on sale. The remaining asset sale is expected to close during
2018 and is classified as held for sale in the consolidated balance sheet as of December 31, 2017, with total assets of $66
million and total liabilities of $2 million. See Note 10 for further detail on impairment expenses recognized concurrently with
these agreements.
In the third quarter of 2015, we entered into agreements to sell our East Africa exploration acreage in Ethiopia and Kenya.
A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction closed during the first quarter of 2016.
71
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
6. Segment Information
We have two reportable operating segments. Each of these segments is organized and managed based upon both geographic
location and the nature of the products and services it offers.
• United States E&P ("U.S. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas
in the United States
•
International E&P ("Int'l E&P") – 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.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker
(“CODM”). Segment income (loss) represents income (loss) which excludes certain items not allocated to segments, net of
income taxes, attributable to the operating segments. A portion of our corporate and operations support general and
administrative 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, certain impairments, change in
tax expense associated with a tax rate change, changes in our valuation allowance, unrealized gains or losses on derivative
instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.
As discussed in Note 5, we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and
exploration stage in-situ leases, in the second quarter of 2017. The Canadian business is reflected as discontinued operations and
is excluded from segment information in all periods presented. Additionally, we renamed our North America E&P segment to
United States E&P segment effective June 30, 2017 in all periods presented. See Note 1 for further information.
Year Ended December 31, 2017
(In millions)
Sales and other operating revenues
Marketing revenues
Total revenues
Income from equity method investments
Net gain on disposal of assets and other income
Less:
Production expenses
Marketing costs
Other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Loss on early extinguishment of debt
Income tax provision (benefit)
$
U.S. E&P
3,138
29
3,167
—
13
Int'l E&P
1,154
$
133
1,287
256
6
Not Allocated
to Segments
$
(81)
—
(81)
—
117
476
36
354
154
2,011
4
173
119
—
—
1
(148) $
$
2,081
229
132
77
5
328
—
—
32
—
—
372
374
42
$
$
$
$
1
—
—
250
33
225
10
249
270
51
3
(1,056)
27
Total
4,211
162
4,373
256
136
706
168
431
409
2,372
229
183
400
270
51
376
(830)
2,150
(b)
$
(c)
(d)
(e)
(f)
(g)
(h)
$
$
Segment income (loss) / Income (loss) from continuing operations
Capital expenditures (a)
Includes accruals.
Primarily related to sale of certain conventional assets in Oklahoma and Colorado. (See Note 5).
(a)
(b) Unrealized loss on commodity derivative instruments.
(c)
(d) Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).
(e)
(f)
(g) Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 13.)
(h) Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 15.)
Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).
Includes pension settlement loss of $32 million (see Note 17).
72
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Segment income (loss) / Income (loss) from continuing operations
Capital expenditures (a)
Includes accruals.
(a)
(b) Unrealized loss on commodity derivative instruments.
(c)
Primarily related to net gain on disposal of assets (see Note 5).
Includes termination payment on our Gulf of Mexico deepwater drilling rig commitment of $113 million.
(d)
(e) Primarily related to impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (See Note 10).
(f)
(g)
(h)
Proved property impairments (see Note 10).
Includes pension settlement loss of $103 million and severance related expenses associated with workforce reductions of $8 million (see Note 17).
Increased valuation allowance on certain of our deferred tax assets $1,346 million (see Note 7).
Year Ended December 31, 2016
(In millions)
Sales and other operating revenues
Marketing revenues
Total revenues
Income (loss) from equity method investments
Net gain on disposal of assets and other income
Less:
Production expenses
Marketing costs
Other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Income tax provision (benefit)
Year Ended December 31, 2015
(In millions)
Sales and other operating revenues
Marketing revenues
Total revenues
Income from equity method investments
Net gain on disposal of assets and other income
Less:
Production expenses
Marketing costs
Other operating
Exploration
Depreciation, depletion and amortization
Impairments
Taxes other than income
General and administrative
Net interest and other
Income tax provision (benefit)
U.S. E&P
2,375
$
135
2,510
—
28
Int'l E&P
665
$
105
770
175
32
Not Allocated
to Segments
$
(110)
—
(110)
—
382
486
142
328
127
1,835
20
149
94
—
(228)
(415) $
$
936
226
103
43
17
276
—
—
35
—
49
228
82
$
$
$
$
—
—
113
179
45
47
2
352
332
1,102
(1,900)
18
Total
2,930
240
3,170
175
442
712
245
484
323
2,156
67
151
481
332
923
(2,087)
1,036
(b)
$
(c)
(d)
(e)
(f)
(g)
(h)
$
$
U.S. E&P
3,358
$
396
3,754
—
24
Int'l E&P
728
$
103
831
157
27
(b)
Not Allocated
to Segments
50
$
—
50
(12)
122 (d)
(c)
$
Total
4,136
499
4,635
145
173
724
401
335
314
2,377
2
215
127
—
(265)
(452) $
$
2,553
255
99
48
101
295
—
—
44
—
61
112
368
$
$
$
$
(e)
(f)
(g)
—
—
27
556
49
719
1
417
286
(534)
(1,361)
25
$
$
979
500
410
971
2,721
721
216
588
286
(738)
(1,701)
2,946
Segment income (loss) / Income (loss) from continuing operations
Capital expenditures (a)
Includes accruals.
(a)
(b) Unrealized gain on commodity derivative instruments.
(c)
(d)
Partial impairment of investment in equity method investee (See Note 14).
Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage
(see Note 5).
(e) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 10).
73
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(f)
(g)
Includes goodwill impairment (see Note 12) and proved property impairments (see Note 10).
Includes pension settlement loss of $119 million (see Note 17) and severance related expenses associated with workforce reductions of $55 million.
Revenues from external customers are attributed to geographic areas based upon selling location. The following
summarizes revenues from external customers by geographic area.
(In millions)
United States
Equatorial Guinea
Libya
U.K.
Other international
Total revenues
Year Ended December 31,
2016
2015
2017
$
$
3,086
530
431
289
37
4,373
$
$
2,400
444
54
263
9
3,170
$
$
3,804
444
—
380
7
4,635
In 2017, sales to Vitol and each of their respective affiliates accounted for approximately 10% of our total revenues. In
2016, sales to Valero Marketing and Supply, Tesoro Petroleum, and Flint Hills Resources and each of their respective affiliates
accounted for approximately 13%, 11% and 10% of our total revenues. In 2015, sales to Shell Oil and its affiliates accounted for
approximately 10% of our total revenues.
The following summarizes revenues by product line.
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Other
Total revenues
Year Ended December 31,
2016
2015
2017
$
$
3,477
338
510
48
4,373
$
$
$
$
2,605
198
356
11
3,170
$
$
3,963
203
464
5
4,635
December 31,
2017
2016
15,971
1,582
959
18,512
$
$
14,272
1,794
1,592
17,658
The following summarizes property, plant and equipment and equity method investments.
(In millions)
United States
Equatorial Guinea
Other international
Total long-lived assets
7. Income Taxes
Income (loss) before tax expense for continuing operations was:
(In millions)
United States
Foreign
Total
Year Ended December 31,
2017
2016
2015
$
$
(783) $
329
(454) $
(1,449) $
285
(1,164) $
(2,384)
(55)
(2,439)
74
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Income tax provisions (benefits) for continuing operations were:
2017
Year Ended December 31,
2016
2015
(In millions)
Federal
State and local
Foreign
Total
Current Deferred
41
$
2
(104)
(61) $
(32) $
(14)
483
437
$
$
$
Total
9
(12)
379
376
$
Current Deferred
836
$
8
(16)
828
2
2
91
95
$
$
Total
$
$
838
10
75
923
$
(41) $
(8)
115
66
$
Current Deferred
$
Total
(725)
(26)
13
(738)
(684) $
(18)
(102)
(804) $
A reconciliation of the federal statutory income tax rate applied to income (loss) from continuing operations before income
taxes to the provision (benefit) for income taxes follows:
Year Ended December 31,
(In millions)
2017
2016
Total pre-tax income (loss) from continuing operations
Total income tax expense (benefit)
Effective income tax expense (benefit) rate on continuing operations
Income taxes at the statutory tax rate of 35% (a)
Effects of foreign operations
Adjustments to valuation allowances
State income taxes
Tax law change
Goodwill impairment
Other federal tax effects
Income tax expense (benefit) on continuing operations
(a)
$
$
$
$
$
$
(454)
376
83%
(159)
140
446
(19)
(35)
—
3
$
376
$
(1,164)
923
79%
(407)
47
1,270
9
6
—
(2)
923
$
$
$
2015
(2,439)
(738)
(30)%
(854)
(55)
95
(15)
(3)
94
—
$
(738)
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 appears in the "Not Allocated to Segments" column of the tables in Note 6.
Effects of foreign operations – The effects of foreign operations increased our tax expense in 2017, 2016, and 2015 due to
the mix of pretax income between high and low tax jurisdictions. This increase primarily relates to increased sales volumes in
Libya during 2017 where the tax rate is 93.5%. Excluding Libya, the effective tax rates on continuing operations would be an
expense of 5% in 2017, an expense of 79% in 2016, and a benefit of 29% in 2015.
Adjustments to valuation allowances - Since December 31, 2016, we have maintained a full valuation allowance on our
net federal deferred tax assets. In 2017, we recorded a $446 million valuation allowance primarily related to current year
activity in the U.S. Included within the $446 million is a $41 million out-of-period adjustment as a result of identifying certain
deferred tax assets for which the impact should have been recorded to other comprehensive income, but had been recorded to
income from continuing operations in 2016.
Change in tax law – On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”).
Tax Reform Legislation, which is also commonly referred to as “U.S. tax reform”, significantly changes U.S. corporate income
tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018, and repeal of the
corporate alternative minimum tax (“AMT”), and a one-time deemed repatriation of accumulated foreign earnings. In the
fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. The impact of the
remeasurement on our federal deferred tax assets and liabilities was equally offset by an adjustment to our valuation allowance
with no material impact to current year earnings. We recorded a net benefit of $35 million, classified as a receivable within
other noncurrent assets on the consolidated balance sheet, during the fourth quarter of 2017 related to the repeal of the corporate
AMT. Although the $35 million net benefit represents what we believe is a reasonable estimate of the impact of the income tax
effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We do
75
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
not expect to pay U.S. federal cash taxes on the deemed repatriation due to an accumulated deficit in foreign earnings for tax
purposes.
Once we finalize certain tax positions when we file our 2017 federal tax return, we will be able to conclude whether any
further adjustments are required to our net tax position as of December 31, 2017. Any adjustments to these provisional amounts
will be reported as a component of income tax expense (benefit) in the reporting period in which any such adjustments are
determined, which will be no later than the fourth quarter of 2018.
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 credit carryforwards
Investments in subsidiaries and affiliates
Other
Subtotal
Valuation Allowance
Total deferred tax assets
Deferred tax liabilities:
Property, plant and equipment
Accrued revenue
Other
Total deferred tax liabilities
Net deferred tax liabilities
Year Ended December 31,
2017
2016
$
$
111
1,030
3
611
—
174
69
1,998
(926)
1,072
1,332
81
3
1,416
344
$
$
228
1,065
4
4,430
35
91
86
5,939
(4,301)
1,638
3,672
75
(7)
3,740
2,102
Foreign Tax Credits - As a result of U.S. tax reform, we have reduced our foreign tax credits at December 31, 2017, which
are offset by a corresponding reduction in valuation allowance, by $3,819 million due to the remote likelihood these credits will
be utilized before expiration. We have not elected any of our foreign earnings to be permanently reinvested abroad.
Additionally due to U.S. tax reform, we do not expect future foreign earnings from operations to be subject to tax in the U.S.
The remaining foreign tax credits, which are offset by a valuation allowance, expire in 2022 through 2027.
Operating loss carryforwards - At December 31, 2017, our operating loss carryforwards before valuation allowance
includes $898 million from the U.S. that expire in 2035-2037. Foreign operating loss carryforwards include $13 million that
begin to expire in 2018. State operating loss carryforwards of $119 million expire in 2018 through 2037.
Valuation allowances – At December 31, 2017, we reflect a valuation allowance in our consolidated balance sheet of $926
million against our net deferred tax assets in various jurisdictions in which we operate. The reduction primarily related to the
reduction of foreign tax credits in the U.S. In 2016 and 2015, we increased our valuation allowance by $1,268 million and $99
million respectively.
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
(In millions)
Assets:
Other noncurrent assets
Liabilities:
Noncurrent deferred tax liabilities
Noncurrent liabilities held for sale
Net deferred tax liabilities
December 31,
2017
2016
$
$
489
$
336
833
—
344
$
769
1,669
2,102
We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been
completed through the 2014 tax year, with the exception of 2010-11. During the third quarter of 2017, we received a
76
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the
fourth quarter of 2017. We believe adequate provision has been made for federal income taxes and interest which may become
payable for years not yet settled. See Note 24 for further detail. Further, we are routinely involved in U.S. state income tax
audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided
for these liabilities.
As of December 31, 2017, our income tax returns remain subject to examination in the following major tax jurisdictions for
the tax years indicated:
United States(a)
Equatorial Guinea
Libya
United Kingdom
(a)
Includes federal and state jurisdictions.
2008-2016
2007-2016
2012-2016
2008-2016
The following table summarizes the activity in unrecognized tax benefits:
(In millions)
Beginning balance
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Statute of limitations
Ending balance
2017
2016
2015
$
$
66
83
(3)
(20)
—
126
$
$
65
6
(5)
—
—
66
$
$
80
1
—
(7)
(9)
65
If the unrecognized tax benefits as of December 31, 2017 were recognized, $10 million would affect our effective income
tax rate. As of December 31, 2017, there are $83 million uncertain tax positions for which it is reasonably possible that the
amount could significantly change during the next twelve months. If this were to significantly change, we estimate that any
revisions to current and deferred tax liabilities would have no cumulative adverse earnings impact on our consolidated results of
operations.
The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs. In the
fourth quarter of 2017, we received an adverse ruling from the U.K. first-tier tax tribunal. As a result of the adverse ruling, in
the fourth quarter of 2017 we established an uncertain tax position. We have appealed the ruling, but were required to pay the
disputed tax amount and associated interest in order to pursue the appeal. The payment of the disputed tax and interest,
approximately $108 million, is not considered a settlement of the tax dispute with the U.K. tax authorities. If we prevail in
appeals, we will be refunded the tax and interest paid, however, if we do not prevail no further material cash payments are
expected due to the initial payment required to appeal the adverse ruling. See Note 24 for further detail.
Interest and penalties are recorded as part of the tax provision and were $2 million, $1 million and $1 million related to
unrecognized tax benefits in 2017, 2016 and 2015. As of December 31, 2017 and 2016, $25 million and $15 million of interest
and penalties were accrued related to income taxes.
8. 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.
(In millions)
Crude oil and natural gas
Supplies and other items
Inventories
77
December 31,
2017
2016
$
$
9
117
126
$
$
6
130
136
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
9. Property, Plant and Equipment
(In millions)
United States E&P
International E&P
Corporate
Net property, plant and equipment
December 31,
2017
2016
$
$
15,867
1,710
88
17,665
$
$
14,158
2,470
99
16,727
At December 31, 2017, 2016 and 2015 we had total deferred exploratory well costs as follows:
(In millions)
Amounts capitalized less than one year after completion of drilling
Amounts capitalized greater than one year after completion of drilling
Total deferred exploratory well costs
Number of projects with costs capitalized greater than one year after
completion of drilling
December 31,
2017
2016
2015
$
$
$
$
263
32
295
1
$
$
131
118
249
3
352
85
437
2
2017
2016
2015
(In millions)
Beginning balance
Additions
Charges to expense (a)
Transfers to development
Dispositions(b)
573
610
(111)
(635)
—
437
Includes $64 million in exploratory well costs being expensed as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon in August
of 2017. See Note 10 for further detail.
Includes sale of GOM assets in 2016.
437
299
(23)
(388)
(76)
249
249
212
(64)
(102)
—
295
Ending balance
(a)
$
$
$
$
$
$
(b)
Exploratory well costs capitalized greater than one year after completion of drilling are associated with one project in E.G.
with costs of $32 million as of December 31, 2017. Management believes this project with suspended exploratory drilling costs
exhibit sufficient quantities of hydrocarbons to justify potential development based on current plans. For this project in E.G.,
drilling was completed on the Rodo well in Alba Block Sub Area B, offshore E. G. in the first quarter of 2015, and we have
since completed a seismic feasibility study. In 2017, we received approval for and proceeded to perform a seismic reprocessing
program. After completion of this program we will evaluate drilling opportunities within Sub Area B.
10. Impairments and Exploration Expenses
Impairments
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-
cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment in our Canadian
business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of
cash flows for all periods presented
The following table summarizes impairment charges of proved properties:
(in millions)
Total impairments
Year Ended December 31,
2017
2016
2015
$
229
$
67
$
721
•
2017 - Impairments were primarily a result of lower forecasted long-term commodity prices and the anticipated sales
of certain non-core proved properties in our International E&P segment of $136 million. Additionally, included in
proved property impairments was $89 million relating to the Gulf of Mexico and certain conventional Oklahoma
assets primarily as a result of lower forecasted long-term commodity prices.
78
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
•
•
2016 - Impairments of $67 million consisted primarily of proved properties in Oklahoma and the Gulf of Mexico as a
result of lower forecasted commodity prices and revisions to estimated abandonment costs.
2015 - Impairments included $340 million for the goodwill impairment of the United States E&P reporting unit, and
$335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower
forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North
Louisiana and Wilburton, Oklahoma.
See Note 6 for relevant detail regarding segment presentation, Note 12 for further detail regarding the goodwill impairment
and Note 14 for fair value measurements related to impairments of proved properties and long-lived assets.
Exploration expense
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,
2017
2016
2015
$
$
$
246
77
25
61
$
195
25
5
98
409
$
323
$
655
212
31
73
971
Unproved property impairments and dry well costs
•
•
•
2017 - As a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core
properties in our International E&P segment, we recorded a non-cash charge of $159 million comprised of $95 million
in unproved property impairments; and $64 million in dry well costs related to our Diaba License G4-223 in the
Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of
Gabon, we recorded a non-cash impairment charge of $43 million to unproved property.
2016 - Unproved property impairments recorded of $195 million were primarily a result of our decision to not drill any
of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in the United
States. Lower dry well expense was a result of the strategic decision to transition out of our conventional exploration
program during 2015.
2015 - Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and
Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated
Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved
property impairment mentioned above. Dry well costs include the operated Solomon exploration well in the Gulf of
Mexico, and our operated Sodalita West #1 exploratory well in E.G.
See Note 6 for relevant detail regarding segment presentation of unproved property impairments.
79
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
11. Asset Retirement Obligations
Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end
of oil and gas production operations. Changes in asset retirement obligations were as follows:
(In millions)
Beginning balance
Incurred liabilities, including acquisitions
Settled liabilities, including dispositions
Accretion expense (included in depreciation, depletion and amortization)
Revisions of estimates
Held for sale
Ending balance
2017
For Year Ended December 31,
2017
2016
$
$
1,652
25
(50)
85
(227)
(2)
1,483
$
$
1,544
14
(74)
79
96
(7)
1,652
•
Settled liabilities include dispositions, primarily related to the sale of certain conventional assets in Oklahoma as well as
retirements in the U.K. and the Gulf of Mexico.
• Revisions of estimates were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in
the U.K.
• Ending balance includes $55 million classified as short-term at December 31, 2017.
2016
•
Settled liabilities include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the
Gulf of Mexico.
• Revisions of estimates were primarily due to changes in timing of abandonment activities as well as changes in cost
estimated in the U.K.
• Ending balance includes $50 million classified as short-term at December 31, 2016.
12. Goodwill
Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances
indicate the fair value of a reporting unit with goodwill 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 only International
E&P includes goodwill. We estimate the fair value of our International E&P 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 our 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. We performed our annual impairment
test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment,
the fair value of our International E&P reporting unit exceeded its book value by over 40%. We believe the estimates and
assumptions used in our impairment assessments are reasonable and based on available market information, but variations in
such assumptions could result in materially different calculations of fair value and determinations of whether or not an
impairment is indicated.
80
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount
of goodwill for 2017 and 2016:
(In millions)
2016
Beginning balance, gross
Less: accumulated impairments
Beginning balance, net
Dispositions
Impairment
Ending balance, net
2017
Beginning balance, gross
Less: accumulated impairments
Beginning balance, net
Dispositions
Impairment
Ending balance, net
13. Derivatives
U.S. E&P
Int'l E&P
Total
$
$
$
$
— $
—
—
—
—
— $
— $
—
—
—
—
— $
115
—
115
—
—
115
115
—
115
—
—
115
$
$
$
$
115
—
115
—
—
115
115
—
115
—
—
115
For further information regarding the fair value measurement of derivative instruments see Note 14. See Note 1 for
discussion of the types of derivatives we use and the reasons for them. All of our commodity derivatives and historical interest
rate derivatives are subject to enforceable master netting arrangements or similar agreements under which we may 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
Total Not Designated as Hedges
Total
(In millions)
Fair Value Hedges
Interest rate
Interest rate
Cash Flow Hedges
Interest rate
Total Designated Hedges
Not Designated as Hedges
Commodity
Total Not Designated as Hedges
Total
$
$
$
$
$
$
$
$
$
Asset
December 31, 2017
Liability
Net Asset
Balance Sheet Location
— $
—
— $
— $
138
2
140
140
$
$
$
(138) Other current liabilities
(2) Deferred credits and other liabilities
(140)
(140)
Asset
December 31, 2016
Liability
Net Asset
Balance Sheet Location
3
1
64
68
$
$
$
— $
— $
$
68
— $
—
— $
— $
60
60
60
$
$
$
3 Other current assets
1 Other noncurrent assets
64 Other noncurrent assets
68
(60) Other current liabilities
(60)
8
81
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Derivatives Designated as Fair Value Hedges
During the third quarter of 2017, we terminated all of our interest rate swaps designated as fair value hedges. The pretax
effects of derivative instruments designated as hedges of fair value in our consolidated statements of income has a gross impact
that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value
hedges in all periods presented.
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted
average, London Interbank Offer Rate (“LIBOR”) based, floating rate.
Maturity Dates
October 1, 2017
March 15, 2018
December 31, 2017
December 31, 2016
Aggregate
Notional
Amount
(in millions)
Weighted
Average, LIBOR-
Based,
Floating Rate
Aggregate
Notional
Amount
(in millions)
Weighted
Average, LIBOR-
Based,
Floating Rate
$
$
—
—
—% $
—% $
600
300
5.10%
5.04%
The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income is
summarized in the table below. There is no ineffectiveness related to the historical fair value hedges.
(In millions)
Derivative
Interest rate
Hedged Item
Debt
Income Statement Location
Net interest and other
Net interest and other
Derivatives Not Designated as Hedges
Interest Rate Swaps
Gain (Loss)
Year Ended December 31,
2016
2015
2017
$
$
— $
— $
(4) $
4
$
—
—
During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows
related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest
rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow
hedges. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as
cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior
unsecured notes. See Note 15 for further detail. As a result, we terminated our forward starting interest rate swaps receiving
proceeds of $54 million. We recognized a gain of $47 million, related to deferred gains reclassified from accumulated other
comprehensive income, in net interest and other during 2017.
The following table presents, by maturity date, information about our terminated forward starting interest rate swap
agreements, including the rate.
Maturity Dates
March 15, 2018
December 31, 2017
December 31, 2016
Aggregate
Notional Amount
Weighted Average,
LIBOR
Aggregate
Notional Amount
Weighted Average,
LIBOR
(in millions)
Fixed Rate
(in millions)
Fixed Rate
$
—
—% $
750
1.57%
82
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated
as cash flow hedges on other comprehensive income (loss).
(In millions)
Interest Rate Swaps
Beginning balance
Change in fair value recognized in other comprehensive income
Reclassification from other comprehensive income
Ending balance
Commodity Derivatives
Year Ended December 31,
2017
2016
2015
$
$
$
60
(13)
(47)
— $
— $
64
(4)
60
$
—
—
—
—
We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a
portion of our forecasted United States E&P sales through 2019. These commodity derivatives consist of three-way collars,
swaps, and 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/Henry Hub price plus the difference
between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets
forth outstanding derivative contracts as of December 31, 2017 and the weighted average prices for those contracts:
Three-Way Collars (a)
Volume (Bbls/day)
Weighted average price per Bbl:
Ceiling
Floor
Sold put
Swaps
Volume (Bbls/day)
Weighted average price per Bbl
Basis Swaps (b)
Volume (Bbls/day)
Weighted average price per Bbl
Crude Oil
2018
2019
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
First
Quarter
Second
Quarter
85,000
85,000
85,000
85,000
10,000
10,000
$56.38
$51.65
$45.00
$56.38
$51.65
$45.00
$56.96
$51.53
$44.65
20,000
$55.12
20,000
$55.12
—
$—
$56.96
$51.53
$44.65
—
$—
5,000
$(0.60)
5,000
$(0.60)
10,000
$(0.67)
10,000
$(0.67)
$60.00
$55.00
$47.00
$60.00
$55.00
$47.00
—
$—
—
$—
—
$—
—
$—
(a)
(b)
Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling
price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average
ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.
The basis differential price is between WTI Midland and WTI Cushing.
83
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Natural Gas
Three-Way Collars
Volume (MMBtu/day)
Weighted average price per MMBtu
Ceiling
Floor
Sold put
2018
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
200,000
160,000
160,000
160,000
$3.79
$3.08
$2.55
$3.61
$3.00
$2.50
$3.61
$3.00
$2.50
$3.61
$3.00
$2.50
The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating
revenues in our consolidated statements of income for the years ended December 31, 2017, 2016, and 2015. The December 31,
2017, 2016, and 2015 impact was a net loss of $36 million, a net loss of $66 million, and a net gain of $128 million, respectively.
Net settlements of commodity derivative instruments for the years ended December 31, 2017, 2016, and 2015 were gains of $45
million, $44 million, and $78 million, respectively.
14. Fair Value Measurements
Fair values – Recurring
The following tables' present assets and liabilities accounted for at fair value on a recurring basis by hierarchy level.
(In millions)
Derivative instruments, assets
Interest rate
Derivative instruments, assets
Derivative instruments, liabilities
Commodity (a)
Derivative instruments, liabilities
(In millions)
Derivative instruments, assets
Interest rate
Derivative instruments, assets
Derivative instruments, liabilities
Commodity (a)
Derivative instruments, liabilities
December 31, 2017
Level 1
Level 2
Level 3
Total
—
— $
(20) $
(20) $
—
— $
(120) $
(120) $
—
— $
— $
— $
—
—
(140)
(140)
December 31, 2016
Level 1
Level 2
Level 3
Total
— $
— $
— $
— $
68
68
60
60
$
$
$
$
— $
— $
— $
— $
68
68
60
60
$
$
$
$
$
$
$
(a) Derivative instruments are recorded on a net basis in our balance sheet (see Note 13).
Commodity derivatives include three-way collars, swaps, and basis swaps. These instruments are measured at fair value
using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include
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, inputs to the models include commodity prices, interest
rates, 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.
Historically, both our interest rate swaps and 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 13 for additional discussion of the types of
derivative instruments we use.
84
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Fair values – Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods
subsequent to their initial recognition.
(In millions)
Long-lived assets held for use
Fair Value
179
$
Impairment
229
$
Fair Value
15
$
Impairment
67
$
Fair Value
56
$
Impairment
386
$
2017
2016
2015
Long-lived assets held for use that were impaired are discussed below. The fair values, unless otherwise noted, were
measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of
which are Level 3 inputs. Inputs to the fair value measurement include reserve and production estimates made by our reservoir
engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses
for the remaining estimated life of the reservoir.
United States E&P
In the third quarter of 2017, impairments of $65 million were recorded consisting of certain proved properties in the Gulf
of Mexico as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $66 million.
In the third quarter of 2016, impairments of $47 million were recorded consisting primarily of conventional non-core
proved properties in Oklahoma as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $15
million. During the fourth quarter of 2016, we recorded an impairment of $17 million as a result of abandonment cost revisions
related to the Ozona development in the Gulf of Mexico which ceased productions in 2013.
In the third quarter of 2015, impairments of $333 million were recorded primarily related to certain producing assets in
Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.
During the second quarter of 2015, we recorded an impairment charge of $44 million related to East Texas, North
Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale. The fair values were measured using a
probability weighted income approach based on both the anticipated sale price and held-for-use model.
International E&P
In the third quarter of 2017, we recorded proved property impairments of $136 million, to an aggregate fair value of $103
million, on certain non-core properties in our International E&P segment primarily as a result of lower forecasted long-term
commodity prices and as a result of the anticipated sales of certain non-core international assets. The fair values were measured
using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per
boe. This resulted in a Level 2 classification. See Note 5 for further information about the divestment of certain non-core
properties in our International E&P segment.
In the third quarter of 2015, a partial impairment of $12 million was recorded to an investment in an equity method
investee as a result of lower forecasted commodity prices, to a fair value of $604 million. The impairment was reflected in
income from equity method investments in our consolidated statement of income.
Canadian discontinued operations
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-
cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for
excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined
based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 5 for relevant
detail regarding dispositions
Fair values – Financial instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, 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.
85
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 value by individual balance sheet line item at December 31, 2017 and 2016.
(In millions)
Financial assets
Other current assets (a)
Other noncurrent assets
Total financial assets
Financial liabilities
Other current liabilities
Long-term debt, including current portion (b)
Deferred credits and other liabilities
$
$
$
December 31,
2017
2016
Fair
Value
Carrying
Amount
Fair
Value
Carrying
Amount
$
$
$
762
159
921
32
5,976
110
6,118
$
$
$
761
161
922
43
5,526
103
5,672
$
$
$
7
105
112
68
7,449
114
7,631
7
108
115
75
7,292
107
7,474
Total financial liabilities
$
Includes our two notes receivable relating to the sale of our Canadian business as of December 31, 2017, see note 5 for further information.
Excludes capital leases, debt issuance costs and historical interest rate swap adjustments.
$
$
$
(a)
(b)
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.
Most 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 such debt. The fair value of our debt that is not
publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which
we currently expect to borrow. All inputs to this calculation are Level 3.
15. Debt
Short-term debt
As of December 31, 2017, we had no borrowings against our $3.4 billion unsecured revolving credit facility (as amended,
the "Credit Facility"), as described below.
Revolving Credit Facility
In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021. In July 2017, we
increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of
each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension.
We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an
additional $107 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of
credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the
last day of each fiscal quarter. 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. As of December 31, 2017, we were in
compliance with this covenant with a debt-to-capitalization ratio of 32%.
86
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Long-term debt
The following table details our long-term debt:
(In millions)
Senior unsecured notes:
6.000% notes due 2017
5.900% notes due 2018
7.500% notes due 2019
2.700% notes due 2020(a)
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)
Capital leases:
Capital lease obligation expiring in 2018
Other obligations:
5.125% obligation relating to revenue bonds due 2037
Total(b)
Unamortized discount
Fair value adjustments(c)
Unamortized debt issuance cost
Amounts due within one year
December 31,
2017
2016
—
—
—
600
1,000
32
3
70
131
900
1,000
550
750
500
—
—
5,536
(10)
—
(32)
—
5,494
$
$
682
854
228
600
1,000
32
3
70
131
900
—
550
750
500
1
1,000
7,301
(9)
7
(35)
(683)
6,581
Total long-term debt
(a)
(b)
(c)
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, 2017 may be declared
immediately due and payable.
See Notes 13 and 14 for information on historical interest rate swaps.
Debt Issuance
On July 24, 2017, we issued $1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the
senior unsecured notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior
unsecured notes at any time at the applicable redemption price, plus accrued interest, if any. During the third quarter of 2017,
we used the net proceeds of $990 million plus existing cash on hand to redeem the following senior unsecured notes:
•
•
•
$682 million 6.0% Notes Due in 2017
$854 million 5.9% Notes Due in 2018
$228 million 7.5% Notes Due in 2019
During the year ended 2017, as a result of the above redemption of $1.76 billion in senior unsecured notes, we recognized a
loss on early extinguishment of debt of $46 million, primarily due to make-whole call provisions. In connection with the
redemption of the senior unsecured notes, we terminated our forward starting interest rate swaps, which resulted in proceeds of
$54 million and a gain of approximately $47 million into earnings in 2017. See Note 13 for further detail on our historical
forward starting interest rate swaps.
Debt Redemption
In December 2017, we entered into a transaction to purchase $1 billion of 3.75% municipal revenue bonds due in 2037, to
be issued by the Parish of St. John the Baptist, State of Louisiana (the "Parish"). The Parish will use the proceeds to redeem $1
billion of 5.125% municipal revenue bonds due in 2037 with cash on hand in a refunding transaction. We purchased the $1
87
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
billion of 3.75% municipal revenue bonds due in 2037 on their date of issuance to hold for our own account and potential
remarketing to the public at a future date.
The following table shows future debt payments:
(In millions)
2018
2019
2020
2021
2022
Thereafter
Total long-term debt, including current portion
16. Incentive Based Compensation
$
$
—
—
600
—
1,035
3,901
5,536
Description of stock-based compensation plans – The Marathon Oil Corporation 2016 Incentive Compensation Plan (the
"2016 Plan") was approved by our stockholders in May 2016 and authorizes the Compensation Committee of the Board of
Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and
performance unit awards to employees. The 2016 Plan also allows us to provide equity compensation to our non-employee
directors. No more than 55 million shares of our common stock may be issued under the 2016 Plan. For stock options and
SARs, the number of shares available for issuance under the 2016 Plan will be reduced by one share for each share of our
common stock in respect of which the award is granted. For stock awards (including restricted stock and restricted stock unit
awards), the number of shares available for issuance under the 2016 Plan will be reduced by 2.41 shares for each share of our
common stock in respect of which the award is granted.
Shares subject to awards under the 2016 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 2016 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 2016 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 2016 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 2016 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, 2017, there are no SARs outstanding.
Restricted stock – We grant restricted stock under the 2016 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 2016 Plan. At the grant
date, each unit represents the value of one share of our common stock. These units are settled in cash, and the amount of the
payment is based on (1) the vesting percentage, which can be from zero to 200% based on performance achieved and (2) the
value of our common stock on the date vesting is 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 number of shares that would
represent the value of the units.
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
88
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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. We also grant restricted stock units to certain non-officer international employees
which generally vest ratably over a three-year period, contingent on the recipient's continued employment. Grants of restricted
stock units to these non-officer international employees are 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 $50 million, $51
million and $57 million in 2017, 2016 and 2015, while the total related income tax benefits were $19 million and $20 million in
2016 and 2015. Due to the full valuation allowance on our net federal deferred tax assets, we realized no tax benefit during
2017. During 2016 and 2015, cash received upon exercise of stock option awards was $1 million and $9 million. There was no
cash received upon exercise of stock option awards for 2017. There were no tax benefits realized for deductions for stock
awards settled during 2017, 2016 and 2015.
Stock option awards – During 2017, 2016 and 2015 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:
Exercise price per share
Expected annual dividend yield
Expected life in years
Expected volatility
Risk-free interest rate
Weighted average grant date fair value of stock option awards granted
The following is a summary of stock option award activity in 2017.
2017
2016
2015
$15.80
1.3%
6.4
42%
2.1%
$6.07
$7.22
2.8%
6.3
36%
1.4%
$1.97
$29.06
2.9%
6.2
32%
1.7%
$6.84
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
11,915,533
799,591
(8,666)
(2,375,682)
10,330,776
8,661,893
1,650,737
$27.71
$15.80
$7.22
$33.31
$25.52
$27.91
$13.08
4 years
3 years
9 years
$
$
$
13
5
8
The intrinsic value of stock option awards exercised during 2017 and 2016 were not material. The intrinsic value of stock
awards exercised during 2015 was $6 million.
As of December 31, 2017, unrecognized compensation cost related to stock option awards was $4 million, which is
expected to be recognized over a weighted average period of one year.
89
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Restricted stock awards and restricted stock units – The following is a summary of restricted stock and restricted stock
unit award activity in 2017.
Unvested at beginning of year
Granted
Vested & Exercised
Canceled
Unvested at end of year
Awards
6,933,533
4,198,624
(2,472,367)
(1,086,945)
7,572,845
Weighted Average
Grant Date
Fair Value
$14.44
$16.13
$17.67
$15.03
$14.24
The vesting date fair value of restricted stock awards which vested during 2017, 2016 and 2015 was $30 million, $16
million and $26 million. The weighted average grant date fair value of restricted stock awards was $14.24, $14.44 and $30.76
for awards unvested at December 31, 2017, 2016 and 2015.
As of December 31, 2017 there was $67 million of unrecognized compensation cost related to restricted stock awards
which is expected to be recognized over a weighted average period of one year.
Stock-based performance unit awards – During 2017, 2016 and 2015 we granted 563,631, 1,205,517 and 382,335 stock-
based performance unit awards to officers. At December 31, 2017, there were 1,510,823 units outstanding. Total stock-based
performance unit awards expense was $8 million in 2017 and $6 million in 2016. We had no stock-based performance unit
awards expense in 2015.
The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units
granted in 2017, 2016 and 2015 were:
Valuation date stock price
Expected annual dividend yield
Expected volatility
Risk-free interest rate
Fair value of stock-based performance units outstanding
(a) As of December 31, 2017, there were no 2015 performance unit awards outstanding.
2017
2016
2015 (a)
$16.93
1.2%
54%
1.9%
$21.63
$16.93
1.2%
34%
1.7%
$19.86
$16.93
1.2%
33%
1.4%
$0.00
17. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees, as well as U.K.
employees who were hired before April 2010. Certain employees located in E.G., who are U.S. or U.K. based, also participate
in these plans. Benefits under these plans are based on plan provisions specific to each plan. For the U.K. pension plan, the
principal employer and plan trustees reached a decision to close the plan to future benefit accruals effective December 31, 2015.
We also have defined benefit 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-age 65 health care benefits are provided to certain U.S. employees on a defined contribution basis. 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.
90
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Obligations and funded status – The following summarizes the obligations and funded status for our defined benefit
pension and other postretirement plans.
(In millions)
Accumulated benefit obligation
Change in benefit obligations:
Beginning balance
Service cost
Interest cost
Plan amendment
Actuarial loss (gain)
Foreign currency exchange rate changes
Divestiture
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
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
Pretax amounts in accumulated other comprehensive
loss:
Net loss (gain)
Prior service cost (credit)
Pension Benefits
2017
2016
U.S.
Int’l
U.S.
Int’l
Other Benefits
2016
2017
U.S.
U.S.
378
599
386
583
221
227
$
$
$
$
$
$
$
397
22
13
—
42
—
—
(84)
(6)
384
$
$
$
227
27
52
—
—
(84)
(6)
$
216
(168) $
—
(6)
(162)
(168) $
$
122
(45)
$
$
$
$
$
$
$
583
—
17
—
(7)
52
—
(31)
(15)
599
595
47
17
57
—
(31)
(15)
670
71
71
—
—
71
58
3
525
25
16
—
78
—
—
(240)
(7)
397
$
$
$
354
25
95
—
—
(240)
(7)
227
$
(170) $
—
(4)
(166)
(170) $
$
130
(55)
$
$
$
$
$
$
$
579
—
23
1
139
(108)
—
(36)
(15)
583
608
129
18
(109)
—
(36)
(15)
595
12
12
—
—
12
81
4
227
2
8
—
5
—
—
—
(21)
221
$
$
— $
—
21
—
—
—
(21)
— $
(221) $
—
(21)
(200)
(221) $
260
2
11
(38)
11
—
—
—
(19)
227
—
—
20
—
—
—
(20)
—
(227)
—
(21)
(206)
(227)
$
30
(56)
25
(63)
91
2
8
—
(7)
—
—
—
3
5
—
—
7
12
15
$
$
$
$
$
$
$
$
2
11
—
(3)
—
—
—
10
11
—
(38)
3
(24) $
(14) $
3
11
—
(4)
1
(7)
—
4
(21)
(1)
—
13
(9)
(5)
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Components of net periodic benefit cost from continuing operations 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
Year Ended December 31,
2016
2015
2017
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
Other Benefits
Year Ended December 31,
2015
2016
2017
U.S.
U.S.
U.S.
(In millions)
Components of net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets
Amortization:
- prior service cost (credit)
- actuarial loss
Net curtailment loss (gain)(a)
Net settlement loss(b)
Net periodic benefit cost(c)
Other changes in plan assets and benefit
obligations recognized in other comprehensive
(income) loss (pretax):
$ 22
13
(13)
$ — $ 25
16
(18)
17
(30)
$ — $ 29
25
(30)
23
(35)
$ 14
25
(37)
$
(10) — (10)
14
1
—
—
97
4
$ (8) $ 124
8
—
28
$ 48
1
—
—
6
(7)
22
(5)
119
$ (5) $ 153
$
1
2
4
—
9
$
Actuarial loss (gain)
Amortization of actuarial gain (loss)
Prior service cost (credit)
Amortization of prior service credit (cost)
$ 28
(36)
—
10
$ (26) $ 70
(111)
—
10
(4)
—
—
$ 41
(6)
1
(1)
$ 30
(134)
(89)
7
$ (25) $
(2)
1
(5)
Total recognized in other comprehensive
(income) loss
Total recognized in net periodic benefit cost
and other comprehensive (income) loss
(a)
$
2
$ (30) $ (31) $ 35
$(186) $ (31) $
$ 50
$ (38) $ 93
$ 30
$ (33) $ (22) $
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of
discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.
(b)
(c) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from
accumulated other comprehensive loss into net periodic benefit cost in 2018 are $13 million and $10 million. The estimated net
loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other
comprehensive loss into net periodic benefit cost in 2018 are $1 million and $7 million.
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 2017, 2016 and 2015.
(In millions)
Weighted average assumptions used to
determine benefit obligation:
Discount rate
Rate of compensation increase (a)
Weighted average assumptions used to
determine net periodic benefit cost:
Discount rate
Expected long-term return on plan
assets
Rate of compensation increase (a)
2017
Pension Benefits
2016
2015
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
Other Benefits
2016
U.S.
2017
U.S.
2015
U.S.
3.55% 2.50% 4.02% 2.70% 4.04% 3.90%
4.00% — 4.00% — 4.00% —
3.54%
4.00%
3.98% 4.36%
4.00% 4.00%
3.86% 2.70% 3.66% 3.90% 3.79% 3.70%
3.98%
4.36% 3.93%
6.50% 4.50% 6.75% 5.50% 6.75% 5.70%
4.00% — 4.00% —% 4.00% 3.60%
—
4.00%
—
—
4.00% 4.00%
(a) No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this
plan.
92
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Expected long-term return on plan assets – The expected long-term return on plan assets assumption for our U.S. funded
plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group 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. To determine the expected long-term return on plan assets assumption for our international plans, we consider
the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk
premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. 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
Initial health care trend rate
Ultimate trend rate
Year ultimate trend rate is reached
2017
2016
2015
8.00%
4.70%
2025
8.25%
4.50%
2025
8.00%
4.50%
2024
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. Therefore, a 1% change in health
care cost trend rates would not have a material impact on either the service and interest cost components and the postretirement
benefit obligations.
Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect
the funded status of the plans 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 – Our international plan's target asset allocation is comprised of 55% equity securities and 45% fixed
income securities. The plan assets are invested in ten separate portfolios, mainly pooled fund vehicles, managed by several
professional investment managers whose performance is measured independently by a third-party asset servicing consulting
firm.
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, 2017 and 2016.
Cash and cash equivalents – Cash and cash equivalents are valued using a market approach and are considered Level 1.
This investment also includes a cash reserve account (a collective short-term investment fund) that is valued using an income
approach and is considered Level 2.
Equity securities - Investments in common stock and preferred 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 are valued based on the sum of the estimated fair values of the investments held by each partnership. These
private equity investments are considered Level 3. Investments in pooled funds are valued using a market approach at the net
asset value ("NAV") of units held. The various funds consist of either an equity or fixed income investment portfolio with
underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The
majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.
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,
non-U.S. government bonds, private placements, taxable municipals, GNMA/FNMA pools, and Yankee bonds 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. Other fixed income investments include futures
contracts, real estate investment trusts, credit default, zero coupon, and interest rate swaps. The investment in the commingled
93
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
funds is valued using the NAV 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. Pooled funds primarily have investments held in
U.S. and non-U.S. publicly traded investment grade government and corporate bonds and are considered Level 2.
Other – Other investments are comprised of an unallocated annuity contract, two limited liability companies, real estate
and U.S. treasury futures. All are considered Level 3, as significant inputs to determine fair value are unobservable.
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, 2017 and 2016.
(In millions)
Level 1
Level 2
Level 3
Total
December 31, 2017
Cash and cash equivalents
Equity securities:
Common stock
Private equity
Mutual and pooled funds
Fixed income securities:
Corporate
Exchange traded funds
Government
Pooled funds
Other
Total investments, at fair value
Commingled funds (a)
Total investments
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
$
6
$
1
$ — $ — $ — $ — $
6
$
1
81
—
—
—
5
19
—
—
111
—
111
$
—
—
151
—
—
—
—
—
152
—
152
$
$
—
—
—
6
—
2
—
—
8
—
8
$
—
—
115
—
—
—
403
—
518
—
518
$
—
16
—
—
—
3
—
19
38
—
38
—
—
—
—
—
—
—
—
—
—
$ — $
81
16
—
6
5
24
—
19
157
59
216
$
—
—
266
—
—
—
403
—
670
—
670
(In millions)
Level 1
Level 2
Level 3
Total
December 31, 2016
Cash and cash equivalents
Equity securities:
Common stock
Private equity
Mutual and pooled funds
Fixed income securities:
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
$
8
$
5
$ — $ — $ — $ — $
8
$
5
82
—
—
—
—
201
—
—
—
—
—
159
—
20
—
—
—
—
82
20
—
—
—
360
Corporate
Exchange traded funds
Government
Pooled funds
Other
Total investments, at fair value
Commingled funds (a)
Total investments
(a) 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.
See Note 2 for further information on the FASB update.
—
—
—
—
—
—
—
$ — $
—
5
6
—
—
101
—
101
—
—
—
—
—
206
—
206
—
—
—
230
—
595
—
595
52
5
25
—
21
213
14
227
—
—
—
230
—
389
—
389
52
—
19
—
—
71
—
71
—
—
—
—
21
41
—
41
$
$
$
$
$
$
The activity during the year ended December 31, 2017 and 2016, for the assets using Level 3 fair value measurements was
immaterial.
94
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, 2017 and reflect expected future services, as appropriate, are to be paid in the years
indicated.
(In millions)
2018
2019
2020
2021
2022
2023 through 2027
Pension Benefits
U.S.
Int’l
Other Benefits
U.S.
$
$
43
40
37
33
30
123
$
17
18
17
19
21
118
21
20
20
19
18
74
Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $65 million
in 2018. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected
to be approximately $6 million and $21 million in 2018.
Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees.
Contributions to these plans totaled $20 million, $20 million and $20 million in 2017, 2016 and 2015.
18. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
(In millions)
Postretirement and postemployment plans
Amortization of actuarial loss
Net settlement loss
Derivative hedges
Recognized gain on terminated derivative
hedge
Ineffective portion of derivative hedge
Total reclassifications to expense, net of tax
Foreign currency hedges
Net recognized loss in discontinued
operations, net of tax
$
$
Year Ended
December 31,
2017
2016
Income Statement Line
(9) $
(32)
(14) General and administrative
(103) General and administrative
46
1
6
(40)
(34) $
— Net interest and other
4
(113)
41
(72)
Net interest and other
Income (loss) from operations
(Provision) benefit for income taxes
Income (loss) from continuing operations
(30)
— Income (loss) from discontinued operations
Total reclassifications to expense
$
(64) $
(72)
95
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
19. Supplemental Cash Flow Information
(In millions)
Net cash used in operating activities:
Interest paid (net of amounts capitalized)
Income taxes paid to taxing authorities (a)
Noncash investing activities, related to continuing operations:
Changes in asset retirement costs
Asset retirement obligations assumed by buyer
Increase in capital expenditure accrual
Notes receivable for disposition of assets
Year Ended December 31,
2016
2015
2017
$
$
(379) $
(391)
(202) $
14
176
748
(375) $
(84)
$
110
40
—
—
(a) Includes a payment of $108 million made to U.K. taxing authorities to preserve our appeal rights, see Note 7 - Income Taxes for additional discussion.
20. Other Items
Net interest and other
(In millions)
Interest:
Interest income
Interest expense
Income on interest rate swaps
Interest capitalized
Total interest
Other:
Net foreign currency gain (loss)
Other
Total other
Net interest and other
Year Ended December 31,
2016
2015
2017
$
$
$
34
(380)
53
3
(290)
8
12
20
(270) $
$
14
(398)
13
18
(353)
6
15
21
(332) $
(325)
(171)
(95)
251
—
—
9
(350)
11
19
(311)
4
21
25
(286)
Foreign currency – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as
follows:
(In millions)
Net interest and other
Provision for income taxes
Aggregate foreign currency gains (losses)
Year Ended December 31,
2016
2015
2017
$
$
8
57
65
$
$
$
6
(32)
(26) $
4
(11)
(7)
96
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
21. Equity Method Investments and Related Party Transactions
During 2017, 2016 and 2015 only our equity method investees were considered related parties and they 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% 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
Other investments
Total
Ownership as of
December 31, 2017
60%
52%
45%
$
$
December 31,
2017
2016
456
214
177
—
847
$
$
550
215
165
1
931
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a
return of capital previously contributed) were $276 million in 2017, $192 million in 2016 and $178 million in 2015.
Summarized financial information for equity method investees is as follows:
(In millions)
Income data – year (a):
Revenues and other income
Income from operations
Net income
Balance sheet data – December 31:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
2017
2016
2015
$
$
$
$
1,294
631
508
586
1,044
221
94
$
770
346
313
525
1,173
218
47
769
313
280
(a)
See Item 15 Exhibits, Financial Statement Schedules which contains the Alba Plant LLC audited financial statements, which have been included pursuant
to Rule 3-09 of Regulation S-X.
Revenues from related parties were $60 million, $54 million and $51 million in 2017, 2016 and 2015, with the majority
related to EGHoldings in all years. Purchases from related parties were $132 million, $103 million and $207 million in 2017,
2016 and 2015 with the majority related to Alba Plant LLC in all years.
Current receivables from related parties at December 31, 2017 and 2016, were $24 million, and $23 million. Payables to
related parties were $14 million and $11 million at December 31, 2017 and 2016, with the majority related to Alba Plant LLC.
22. Stockholders’ Equity
In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share,
excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to strengthen
our balance sheet and for general corporate purposes, including funding a portion of our Capital Development Program.
There were no share repurchases during 2017 or 2016 under our publicly announced plans or programs. As of
December 31, 2017 the total remaining share repurchase authorization was $1.5 billion. Purchases under the program 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 prior
to completion. The repurchase program does not include specific price targets or timetables.
97
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
23. Leases
We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and
vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum
commitments for operating lease obligations having noncancellable lease terms in excess of one year are as follows:
(In millions)
2018
2019
2020
2021
2022
Later years
Sublease rentals
Total minimum lease payments
* Future minimum commitments for capital lease obligations are nil as of December 31, 2017.
Operating Lease
Obligations
$
$
29
28
27
26
5
4
—
119
Operating lease rental expense related to continuing operations was $87 million, $87 million and $99 million in 2017, 2016
and 2015.
24. Commitments and Contingencies
The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs, which we
claimed for U.K. corporation tax purposes. The dispute relates to the timing of the deduction and does not dispute the general
deductibility of decommissioning costs. In the third quarter of 2017, a hearing took place at the U.K.’s First-tier Tribunal with
respect to this tax deduction. In the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the
judge sided with the U.K. tax authorities with respect to the timing of the decommissioning cost deductions. We intend to
appeal this decision and estimate that any revisions to current and deferred tax liabilities, if we do not prevail in the appeals
process, would have no cumulative adverse earnings impact on our consolidated results of operations. In accordance with U.K.
regulations, we have paid the amount of tax and interest in question, approximately $108 million, prior to our appeal. As a
result of the negative ruling we no longer consider this position to be more-likely-than-not to be sustained and have created an
uncertain tax position related to the Brae area decommissioning costs. The payment of the tax and interest to the U.K. tax
authorities is not to settle the position, but a regulatory requirement to appeal in the U.K. If we ultimately prevail in appeals,
the U.K. tax authorities will refund the tax and interest, however, if we ultimately lose in appeals no material future payments
related to this issue will be required. See Note 7 for further detail.
We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. These audits have been
completed through the 2014 tax year, except for tax years 2010 and 2011. During the third quarter of 2017, we received a
partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the
fourth quarter of 2017. We believe that it is more likely than not that we will prevail.
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 federal, state, local and foreign laws and regulations relating to the environment. If these
expenditures, as with all costs, are not ultimately reflected in 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.
At December 31, 2017 and 2016, 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.
98
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Guarantees – We have entered into a performance guarantee related to asset retirement obligations with aggregate
maximum potential undiscounted payments totaling $35 million as of December 31, 2017. Under the terms of this guarantee
arrangement, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified
arrangements.
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 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, 2017 and 2016, contractual commitments to acquire property, plant and
equipment totaled $102 million and $144 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, proceeds associated with the production of our override, up to $70 million, 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.
99
Select Quarterly Financial Data (Unaudited)
2017
2016
(In millions, except per share data)
Revenues
Income (loss) from continuing
operations before income taxes (a)
Income (loss) from continuing
operations
Discontinued operations (b)
Net income (loss) (c)
Income (loss) per share:
1st Qtr. 2nd Qtr.
993
$
988
$
3rd Qtr.
$ 1,162
4th Qtr.
$ 1,230
1st Qtr.
612
$
2nd Qtr.
761
$
3rd Qtr.
861
$
4th Qtr.
936
$
(16)
(112)
(458)
132
(613)
(192)
(313)
(46)
(50)
(4,907)
$(4,957) $
(153)
14
(139) $
(599)
—
(599) $
(360)
(47)
(28)
—
(28) $ (407) $
(138)
(32)
(170) $
(206)
14
(1,383)
12
(192) $ (1,371)
Continuing operations
Discontinued operations (b)
Basic net income (loss)
$ (0.06) $ (0.18) $
$ (5.78) $
$
$ (5.84) $ (0.16) $
Dividends paid per share
$
$
$ 0.05
(a) Includes impairments to proved properties of $24 million and $201 million in the fourth and third quarter of 2017 and $47 million in the third quarter of
2016. Also includes unproved property impairments and exploratory dry well costs of $215 million in the third quarter of 2017 and $118 million in the
second quarter of 2016. (See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements).
(0.70) $ (0.03) $ (0.49) $
— $ — $ (0.07) $
(0.70) $ (0.03) $ (0.56) $
$
0.05
0.05
(0.16) $ (0.24) $ (1.63)
(0.04) $
0.01
0.01
(0.20) $ (0.23) $ (1.62)
0.05
0.05
0.05
0.02
0.05
0.05
$
$
$
$
$
(b) We closed on the sale of our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods
presented. Included in the first quarter of 2017 is an after-tax non-cash impairment charge of $4.96 billion, primarily related to the property, plant, and
equipment.
(c) Includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million in the fourth quarter of 2016 (see Item 8. Financial
Statements and Supplementary Data – Note 9 to the consolidated financial statements).
100
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; Other Africa, which
includes Gabon; and Other International ("Other Int’l"), which includes the U.K. and the Kurdistan Region of Iraq. We closed
the sale of our Canada business in 2017 and have reflected this business as discontinued operations ("Disc Ops") in all periods
presented. See Note 5 for further details on our Canadian disposition.
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, NGL,
natural gas and our historical synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group
("CRG"), which includes our Director 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 three years of industry experience with at least one year in reserve estimation and have completed our QRE
training course. All reserves changes (including proved) must be approved by the 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 Director of
Corporate Reserves.
The Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in
petroleum engineering and is a registered Professional Engineer in the State of New Mexico. In his 31 years with Marathon
Oil, he has held numerous engineering and management positions, including more recently managing reservoir engineering and
geoscience for our Eagle Ford development in South Texas. 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.
Historical estimates of synthetic crude oil reserves were prepared by GLJ Petroleum Consultants of Calgary, Alberta,
Canada, third-party consultants for 2015. Their report was filed as an exhibit to the prior year Annual Report on Form 10-K.
The individual responsible for the estimates of our synthetic crude oil reserves had 15 years of experience in petroleum
engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional
Engineer in the Province of Alberta.
Audits of Estimates
We engage third-party consultants to provide, at a minimum, independent estimates for fields that comprise 80% of our
total proved reserves over a rolling four-year period. We exceeded this percentage for the four-year period ended December 31,
2017, with 84% of our total proved reserves independently audited. An audit tolerance at a field level of +/- 10% to our internal
estimates has been established. Should the third-party consultants’ initial analysis fall outside our tolerance band, both parties
will re-examine the information provided, request additional data and refine their analysis, if appropriate. In the very limited
instances where differences outside the 10% tolerance cannot be resolved by year end, a plan to resolve the difference is
developed and executive management consent is obtained. The audit process did not result in any significant changes to our
reserve estimates for 2017, 2016 or 2015.
During 2017, 2016 and 2015, Netherland, Sewell & Associates, Inc. prepared a reserves certification for the Alba field in
E.G. The NSAI summary reports are 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 Society of Petroleum
Engineers. The senior technical advisor has over 13 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 11
years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the State of Texas.
Ryder Scott Company also performed audits of the prior years' reserves for several of our fields in 2017, 2016 and 2015.
Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 35
years of industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a
26 year member of SPE and is a registered Professional Engineer in the State of Texas.
101
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
The estimation of net recoverable quantities of crude oil and condensate, natural gas liquids, natural gas and our historical
synthetic crude oil 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. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of
Financial Condition, Cash Flows and Liquidity – Critical Accounting Estimates – Estimated Quantities of Net Reserves for the
table providing our 2017 SEC pricing of benchmark prices and the underlying assumptions used.
The table below provides the 2017 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)
SEC Pricing 2017
$
$
$
$
51.34
2.98
54.39
22.03
102
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:
U.S.
E.G.(a)
Libya
Other
Int'l
Cont
Ops
Disc Ops
Total
Beginning of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2016
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2017
Proved developed reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
Proved undeveloped reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
208
(7)
—
—
—
—
—
201
(28)
—
—
—
(1)
—
172
—
—
—
—
(7)
—
165
175
173
172
165
33
28
—
—
29
(2)
—
—
—
(5)
—
22
3
—
—
1
(4)
—
22
8
—
—
—
(4)
—
26
19
16
13
17
10
6
9
9
928
(64)
1
—
70
(74)
(6)
855
31
4
12
38
(61)
(77)
802
15
—
18
34
(68)
(1)
800
518
541
468
484
410
314
334
316
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
928
(64)
1
—
70
(74)
(6)
855
31
4
12
38
(61)
(77)
802
15
—
18
34
(68)
(1)
800
518
541
468
484
410
314
334
316
634
(57)
1
—
70
(62)
(6)
580
55
4
12
37
(48)
(77)
563
9
—
18
30
(49)
(1)
570
294
327
238
263
340
253
325
307
57
2
—
—
—
(7)
—
52
1
—
—
—
(8)
—
45
(2)
—
—
4
(8)
—
39
30
25
45
39
27
27
—
—
103
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:
U.S.
E.G.(a)
Libya
Other
Int'l
Cont
Ops
Disc Ops
Total
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
—
—
—
192
(6)
—
—
33
(18)
(1)
200
(8)
—
12
11
(18)
(3)
194
40
—
5
36
(20)
(1)
254
83
104
102
143
109
96
92
111
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
192
(6)
—
—
33
(18)
(1)
200
(8)
—
12
11
(18)
(3)
194
40
—
5
36
(20)
(1)
254
83
104
102
143
109
96
92
111
Beginning of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2016
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2017
Proved developed reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
Proved undeveloped reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
161
(7)
—
—
33
(14)
(1)
172
(8)
—
12
11
(14)
(3)
170
37
—
5
34
(16)
(1)
229
68
92
78
118
93
80
92
111
30
2
—
—
—
(4)
—
28
—
—
—
—
(4)
—
24
3
—
—
2
(4)
—
25
15
12
24
25
15
16
—
—
104
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:
U.S.
E.G.(a)
Libya
Other
Int'l
Cont
Ops
Disc Ops
Total
209
(3)
—
—
—
—
—
206
(1)
—
—
—
—
—
205
—
—
—
—
(1)
—
204
94
94
95
94
115
112
110
110
22
1
—
—
—
(8)
—
15
3
—
—
—
(8)
—
10
4
—
—
—
(6)
—
8
17
11
5
2
5
4
5
6
2,580
11
—
1
225
(286)
(69)
2,462
155
—
61
71
(278)
(25)
2,446
(47)
—
36
280
(302)
(44)
2,369
1,350
1,297
1,691
1,655
1,230
1,165
755
714
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,580
11
—
1
225
(286)
(69)
2,462
155
—
61
71
(278)
(25)
2,446
(47)
—
36
280
(302)
(44)
2,369
1,350
1,297
1,691
1,655
1,230
1,165
755
714
Beginning of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2016
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2017
Proved developed reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
Proved undeveloped reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
1,144
(22)
—
1
225
(128)
(69)
1,151
145
—
61
71
(115)
(25)
1,288
(33)
—
36
204
(127)
(44)
1,324
575
640
648
726
569
511
640
598
1,205
35
—
—
—
(150)
—
1,090
8
—
—
—
(155)
—
943
(18)
—
—
76
(168)
—
833
664
552
943
833
541
538
—
—
105
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(mmbbl)
Synthetic crude oil
Proved developed and undeveloped reserves:
U.S.
E.G.(a)
Libya
Other
Int'l
Cont
Ops
Disc Ops
Total
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
648
67
—
—
—
(17)
—
698
12
—
—
—
(18)
—
692
—
—
—
—
(7)
(685)
—
644
698
692
—
4
—
—
—
648
67
—
—
—
(17)
—
698
12
—
—
—
(18)
—
692
—
—
—
—
(7)
(685)
—
644
698
692
—
4
—
—
—
Beginning of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2016
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2017
Proved developed reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
Proved undeveloped reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
106
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:
U.S.
E.G.(a)
Libya
Other
Int'l
Cont
Ops
Disc Ops
Total
Beginning of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2015
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2016
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries and
other additions
Production (b)
Sales of reserves in place
End of year - 2017
Proved developed reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
Proved undeveloped reserves:
Beginning of year - 2015
End of year - 2015
End of year - 2016
End of year - 2017
986
(67)
1
1
139
(98)
(18)
944
73
4
34
59
(82)
(84)
948
42
—
28
98
(86)
(10)
1,020
458
526
424
502
528
418
524
518
288
8
—
—
1
(36)
—
261
2
—
—
—
(37)
—
226
(1)
—
—
18
(40)
—
203
155
129
226
203
133
132
—
—
243
(8)
—
—
—
—
—
235
(28)
—
—
—
(1)
—
206
—
—
—
—
(7)
—
199
191
189
188
181
52
46
18
18
33
(2)
—
—
—
(6)
—
25
4
—
—
1
(6)
—
24
8
—
—
—
(5)
—
27
22
18
14
17
11
7
10
10
1,550
(69)
1
1
140
(140)
(18)
1,465
51
4
34
60
(126)
(84)
1,404
49
—
28
116
(138)
(10)
1,449
826
862
852
903
724
603
552
546
648
67
—
—
—
(17)
—
698
12
—
—
—
(18)
—
692
—
—
—
—
(7)
(685)
—
644
698
692
—
4
—
—
—
2,198
(2)
1
1
140
(157)
(18)
2,163
63
4
34
60
(144)
(84)
2,096
49
—
28
116
(145)
(695)
1,449
1,470
1,560
1,544
903
728
603
552
546
(a)
(b)
Consists of estimated reserves from properties governed by production sharing contracts.
Excludes the resale of purchased natural gas used in reservoir management.
107
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
2017 proved reserves decreased by 647 mmboe primarily due to the following:
• Revisions of previous estimates: Increased by 49 mmboe primarily due to the acceleration of higher economic wells in the
Bakken into the 5-year plan resulting in an increase of 44 mmboe, with the remainder being due to revisions across the
business.
• Extensions, discoveries, and other additions: Increased by 116 mmboe primarily due to an increase of 97 mmboe
associated with the expansion of proved areas and wells to sales from unproved categories in Oklahoma.
• Purchases of reserves in place: Increased by 28 mmboe from acquisitions of assets in the Northern Delaware Basin in New
Mexico.
• Production: Decreased by 145 mmboe.
•
Sales of reserves in place: Decreased by 695 mmboe including 685 mmboe associated with the sale of our Canadian
business and 10 mmboe associated with divestitures of certain conventional assets in Oklahoma and Colorado. See Item 8.
Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information regarding
these dispositions.
2016 proved reserves decreased by 67 mmboe primarily due to the following:
• Revisions of previous estimates: Increased by 63 mmboe primarily due to an increase of 151 mmboe associated with the
acceleration of higher economic wells in the U.S. resource plays into the 5-year plan and a decrease of 64 mmboe due to
U.S. technical revisions.
• Extensions, discoveries, and other additions: Increased by 60 mmboe primarily associated with the expansion of proved
areas and new wells to sales from unproven categories in Oklahoma.
• Purchases of reserves in place: Increased by 34 mmboe from acquisition of STACK assets in Oklahoma.
• Production: Decreased by 144 mmboe.
•
Sales of reserves in place: Decreased by 84 mmboe associated with the divestitures of certain Wyoming and Gulf of
Mexico assets.
2015 proved reserves decreased by 35 mmboe primarily due to the following:
• Revisions of previous estimates: Decreased by 2 mmboe primarily resulting from an increase of 105 mmboe associated
with drilling programs in U.S. resource plays and an increase of 67 mmboe in discontinued operations due to technical
reevaluation and lower royalty percentages related to lower realized prices, offset by a decrease of 173 mmboe which was
largely due to reductions to our capital development program and adherence to the SEC 5-year rule.
• Extensions, discoveries, and other additions: Increased by140 mmboe as a result of drilling programs in our U.S. resource
plays.
• Production: Decreased by 157 mmboe.
•
Sales of reserves in place: U.S. conventional assets sales contributed to a decrease of 18 mmboe.
Changes in Proved Undeveloped Reserves
As of December 31, 2017, 546 mmboe of proved undeveloped reserves were reported, a decrease of 6 mmboe from
December 31, 2016. The following table shows changes in proved undeveloped reserves for 2017:
(mmboe)
Beginning of year
Revisions of previous estimates
Improved recovery
Purchases of reserves in place
Extensions, discoveries, and other additions
Dispositions
Transfers to proved developed
End of year
552
5
—
15
57
—
(83)
546
Revisions of prior estimates. Revisions of prior estimates increased 5 mmboe during 2017, primarily due to a 44 mmboe
increase in the Bakken from an acceleration of higher economic wells into the 5-year plan, offset by a decrease of 40 mmboe in
Oklahoma due to the removal of less economic wells from the 5-year plan.
Extensions, discoveries and other additions. Increased 57 mmboe through expansion of proved areas in Oklahoma.
108
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Transfers to proved developed. 83 mmboe of PUD reserves were converted to proved developed status during 2017, primarily
from assets in our U.S. resource plays. This 2017 transfer equates to a 15% PUD conversion rate and a 5-year average annual
PUD conversion rate during the 2013-2017 period of 18%. All proved undeveloped reserve drilling locations are scheduled to
be drilled prior to the end of 2022.
A total of 25 mmboe of proved undeveloped reserves, or less than 2% of the company’s total proved reserves, have been on the
books beyond 5 years as of year-end 2017.
As of year-end 2017, there were 18 mmboe of proved undeveloped reserves, initially disclosed in 2012, associated with the
Faregh Phase II project in Libya. Drilling operations and construction of the associated gas plant were completed in 2010.
Final commissioning was halted in 2011 and again in 2013 due to civil unrest and subsequent declaration of Force Majeure. In
2017, teams conducted an assessment of the facilities to determine the state of the equipment and developed a plan to
recommission the plant and initiate production in 2018, at which time, all associated proved undeveloped reserves will be
transferred to proved developed.
As of year-end 2017, there were 7 mmboe of proved undeveloped reserves, initially disclosed in 2011, associated with the Fuel
Gas Deficiency project in the U.K. The project includes the design, procurement and installation of the Brae Bravo gas by-pass,
which will ensure continued operations at the existing Brae Alpha and East Brae platforms. The project has been approved and
work is underway with completion expected in 2018, at which time, all associated proved undeveloped reserves will be
transferred to proved developed.
Costs Incurred & Future Costs to Develop
Costs incurred in 2017, 2016 and 2015 relating to the development of proved undeveloped reserves were $842 million,
$359 million and $1,415 million. As of December 31, 2017, future development costs estimated to be required for the
development of proved undeveloped crude oil and condensate, NGLs and natural gas reserves for the years 2018 through 2022
are projected to be $1,425 million, $1,348 million, $1,409 million, $1,458 million and $1,028 million.
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization
(In millions)
2017 Capitalized Costs:
Proved properties
Unproved properties
Total
Accumulated depreciation,
depletion and amortization:
Proved properties
Unproved properties (a)
Total
Net capitalized costs
2016 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 10).
Year Ended December 31,
U.S.
E.G.
Libya
Other
Africa
Other Int'l
Total
$
$
$
$
27,477
2,755
30,232
14,254
206
14,460
15,772
25,497
1,473
26,970
12,526
382
12,908
14,062
$
$
$
$
830
217
1,047
289
—
289
758
756
281
1,037
268
—
268
769
$
$
$
$
— $
43
43
—
43
43
— $
— $
136
136
1
—
1
135
$
5,050
33
5,083
4,850
33
4,883
200
5,864
183
6,047
5,246
113
5,359
688
$
$
$
$
35,347
3,158
38,505
20,741
282
21,023
17,482
34,095
2,192
36,287
19,257
497
19,754
16,533
1,990
110
2,100
1,348
—
1,348
752
1,978
119
2,097
1,216
2
1,218
879
109
$
$
$
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Costs Incurred for Property Acquisition, Exploration and Development (a)
U.S.
E.G.
Libya
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
(In millions)
December 31, 2017
Property acquisition:
Proved
Unproved
Exploration
Development
Total
December 31, 2016
Property acquisition:
Proved
Unproved
Exploration
Development
Total
December 31, 2015
Property acquisition:
Proved
Unproved
Exploration
Development
Total
—
—
3
(144) (b)
(141)
—
(11)
3
121 (b)
113
$
191
$
1,746
882
1,122
$
3,941
$
1
—
1
5
7
$
— $
— $
—
—
10
10
$
1
37
—
38
$
$
$
192
$
— $
192
1,747
923
993
$
3,855
$
—
—
6
6
1,747
923
999
$
3,861
$
$
$
276
642
525
456
1,899
4
61
959
1,477
$
$
$
— $
— $
— $
$
— $
—
1
55
56
$
—
—
3
3
$
1
10
—
11
$
— $
— $
— $
—
60
150
210
$
—
1
13
14
$
1
37
—
38
$
—
—
50
31
81
$
2,082
$
$
2,113
$
276
632
539
635
$
4
62
1,107
1,671
276
632
539
666
4
62
1,108
1,671
—
—
31
31
—
1
—
1
$
— $
$
2,501
$
$
2,844
$
$
2,845
(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 in the U.K.
110
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
U.S.
E.G.
Libya
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
$
$
$
$
$
Year Ended December 31, 2017
Revenues and other income:
Sales
Transfers
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
Results of operations
Year Ended December 31, 2016
Revenues and other income:
Sales
Transfers
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 (d)
Results of operations
Year Ended December 31, 2015
Revenues and other income:
Sales
Transfers
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
Results of operations
$
$ 3,050
—
74
3,124
(985)
(153)
(2,105)
(28)
(3,271)
(147)
(1)
(148) $
$
$
$ 2,249
—
387
2,636
(952)
(306)
(1,901)
(21)
(3,180)
(544)
195
(349) $
$
$
$ 3,374
—
230
3,604
(1,259)
(750)
(2,758)
(47)
(4,814)
(1,210)
437
(773) $
$
45
344
—
389
(84)
—
(134)
(4)
(222)
167
(50)
117
42
291
—
333
(81)
(1)
(114)
(4)
(200)
133
(26)
107
40
296
—
336
(84)
(41)
(92)
(6)
(223)
113
(33)
80
431
—
—
431
(44)
—
(21)
(4)
(69)
362
(333)
29
54
—
—
54
(36)
(6)
(7)
—
(49)
5
(2)
3
$
$
$
$
— $
—
—
—
—
(171)
282
—
38
320
$
$ 3,808
344
112
423
—
(43)
$ 4,231
344
69
4,264
380
4,644
(152)
(83)
(1,265)
(407)
(272)
—
(1,537)
(407)
—
(7)
(178)
(178)
—
(178) $
(273)
(18)
(526)
(206)
13
(193) $
(9,209)
(6,676)
(2,533)
(61)
(61)
—
(11,214)
(6,948)
(4,266)
(6,570)
(6,568)
(2)
(371)
1,303
1,674
(373) $ (4,894) $ (5,267)
— $
—
—
—
—
(8)
—
(3)
(11)
(11)
—
(11) $
237
—
2
239
(140)
(2)
(132)
(2)
(276)
(37)
57
20
329
—
1
330
$
$ 2,582
291
389
3,262
724
—
—
724
$ 3,306
291
389
3,986
(1,209)
(323)
(544)
(7)
(1,753)
(330)
(2,154)
(30)
(3,716)
(454)
224
(230) $
$
(239)
(1)
(791)
(67)
15
(52) $
(2,393)
(31)
(4,507)
(521)
239
(282)
$
$ 3,743
296
122
4,161
700
—
—
700
$ 4,443
296
122
4,861
— $
—
—
— $
—
(109)
—
(109)
(31)
—
—
(36)
(177)
(143)
(1,551)
(970)
(660)
(348)
(2,211)
(1,318)
(5)
(1)
(37)
(37)
37
— $
—
(1)
(37)
(146)
50
(96) $
(163)
(3)
(486)
(156)
86
(70) $
(3,018)
(58)
(5,597)
(1,436)
577
(859) $
(266)
(2)
(1,276)
(576)
31
(3,284)
(60)
(6,873)
(2,012)
608
(545) $ (1,404)
$
111
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
(a)
(b)
Includes net gain (loss) on dispositions (see Note 5) and revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing
of abandonment activities in the U.K.
Includes exploratory dry well costs, unproved property impairments, and other (see Note 10).
Includes long-lived asset impairments (see Note 10).
(c)
(d) Discontinued operations activity includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase.
Results of Operations for Oil and Gas Producing Activities
The following reconciles results of operations for oil and gas producing activities to segment income:
Year Ended December 31,
2016
2017
2015
$
(5,267) $
4,894
(373)
(282) $
52
(230)
(1,404)
545
(859)
(107)
229
(79)
475
81
—
226
$
(39)
142
(248)
148
72
(32)
(187) $
(102)
127
(76)
602
(32)
—
(340)
$
(In millions)
Results of operations
Discontinued operations
Results of continuing operations
Items not included in results of oil and gas operations, net of tax:
Marketing income and other non-oil and gas producing related activities
Income from equity method investments
Items not allocated to segment income, net of tax:
Loss (gain) on asset dispositions and other income
Long-lived asset impairments
Unrealized loss (gain) on derivatives
Deferred tax valuation allowance increase
Segment income
112
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 liquid, and natural gas
reserves.
(In millions)
Year Ended December 31, 2017
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-
related to continuing operations
Standardized measure of discounted future net cash flows-
related to discontinued operations
Year Ended December 31, 2016
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-
related to continuing operations
Standardized measure of discounted future net cash flows-
related to discontinued operations
Year Ended December 31, 2015
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-
related to continuing operations
Standardized measure of discounted future net cash flows-
related to discontinued operations
$
$
$
$
$
$
$
$
$
U.S.
E.G.
Libya
Other Int'l
Total
36,480
(14,796)
(6,987)
(786)
13,911
(7,009)
$
$
$
$
1,966
(748)
(7)
(274)
937
(235)
$
$
10,303
(931)
(501)
(8,387)
484
(224)
1,403
(821)
(1,247)
496
(169)
168
(a)
6,902
$
702
$
260
$
(1)
27,610
(12,758)
(7,233)
—
7,619
(4,355)
$
$
$
$
1,977
(824)
(13)
(251)
889
(264)
$
$
8,511
(930)
(296)
(6,884)
401
(143)
921
(673)
(1,345)
514
(583)
313
(a)
3,264
$
625
$
258
$
(270)
31,026
(12,270)
(6,637)
(778)
11,341
(6,082)
$
$
$
$
2,671
(1,095)
(94)
(369)
1,113
(380)
$
$
12,157
(901)
(689)
(9,857)
710
(441)
1,281
(902)
(1,537)
602
(556)
352
(a)
5,259
$
733
$
269
$
(204)
$
$
$
$
$
$
$
$
$
$
$
50,152
(17,296)
(8,742)
(8,951)
15,163
(7,300)
7,863
—
39,019
(15,185)
(8,887)
(6,621)
8,326
(4,449)
3,877
1,076
47,135
(15,168)
(8,957)
(10,402)
12,608
(6,551)
6,057
165
(a)
Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K.
113
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 $ (2,853)
Net changes in prices and production and support costs related to future
production
2017
Year Ended December 31,
2016
$ (1,634)
2015
$ (2,422)
4,916
661
1,027
183
497
102
698
(1,245)
3,986
3,877
$ 7,863
$ —
(3,621) (b)
(2,174)
669
2,534
654
(651)
1,005
1,038
(2,180)
6,057
$ 3,877
911
$
(21,309) (b)
6
1,693
7,247
(5,682)
(460)
2,719
9,989
(8,219)
14,276
$
6,057
$ (2,115)
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 related to continuing operations
End of the year related to continuing operations
Net change for the year related to discontinued operations
(a)
(b) Decrease primarily due to lower realized prices.
Includes amounts resulting from changes in the timing of production.
114
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, 2017.
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 2017, 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.
115
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 2018 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 2017 (the
"2018 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 2018 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 2018 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2017 with respect to shares of Marathon Oil common stock
that may be issued under our existing equity compensation plans:
• Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 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.
• Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted
under this plan.
• Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants and
rights
11,915,472 (a)
12,291 (b)
11,927,763
Weighted-
average
exercise price of
outstanding
options,
warrants and
rights(c)
$25.52
N/A
N/A
Number of
securities
remaining
available for
future issuance
under equity
compensation
plans
43,840,884 (d)
—
43,840,884
Plan category
Equity compensation plans approved by stockholders
Equity compensation plans not approved by stockholders
Total
(a)
Includes the following:
•
•
736,199 stock options outstanding under the 2016 Plan; 3,991,905 stock options outstanding under the 2012 Plan; 5,591,708 stock options outstanding
under the 2007 Plan;
399,114 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program
and the annual director stock award program established under the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan. Common stock units credited under
the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan were 69,556, 142,724, 152,839 and 33,995, respectively;
116
•
•
1,196,546 restricted stock units granted to non-officers under the 2012 Plan and 2016 Plan and outstanding as of December 31, 2017.
In addition to the awards reported above, 2,850,798 and 3,525,501 shares of restricted stock were issued and outstanding as of December 31, 2017, but
subject to forfeiture restrictions under the 2012 and 2016 Plans, respectively.
(b) Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to
April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the
common stock units.
(c)
The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.
(d) Reflects the shares available for issuance under the 2016 Plan. No more than 18,496,714 of these shares may be issued for awards other than stock
options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again
immediately become available for issuance.
The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been
approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003.
Under the Deferred Compensation Plan for Non-Employee Directors, all non-employee directors were required to defer half of
their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the
non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of
common stock units equal to half of his or her annual retainer divided by the fair market value of our common stock on that
date. The ongoing value of each common stock unit equals the market price of a share of our common stock. When the non-
employee director leaves the Board, he or she is issued actual shares of our common stock equal to the number of common
stock units in his or her account at that time.
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 2018 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
2018" in the 2018 Proxy Statement.
117
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 audited 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.
118
SIGNATURES
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 22, 2018
MARATHON OIL CORPORATION
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 22, 2018 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/ DENNIS H. REILLEY
Dennis H. Reilley
/s/ GAURDIE E. BANISTER, JR.
Gaurdie E. Banister, Jr.
/S/ GREGORY H. BOYCE
Gregory H. Boyce
/S/ CHADWICK C. DEATON
Chadwick C. Deaton
/S/ MARCELA E. DONADIO
Marcela E. Donadio
/S/ PHILIP LADER
Philip Lader
/S/ MICHAEL E. J. PHELPS
Michael E. J. Phelps
Title
President and Chief Executive Officer and Director
Executive Vice President and Chief Financial Officer
Vice President, Controller and Chief Accounting Officer
Chairman of the Board
Director
Director
Director
Director
Director
Director
119
Exhibit
Number
1
1.1*
2
2.1
3
3.1
3.2
3.3
4
4.1
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)
10-Q
8-K
10-K
10-K
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
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
8-K
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
Filing Date
Form
10-Q
10.1
5/5/2017
3.1
3.1
3.3
4.2
8/8/2013
3/1/2016
2/28/2014
2/28/2014
4.1
6/2/2014
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.
10-Q
10.1
5/7/2015
8-K
99.1
3/8/2016
1
Exhibit
Number
10.4
10.5
10.6†
10.7†
10.8†
10.9†
10.10†
10.11†
10.12*
10.13*
10.14†
10.15†
10.16†
10.17†
10.18†
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
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.
Marathon Oil Corporation 2016 Incentive Compensation Plan
DEF 14A
8-K/A
App. A
10.1
4/7/2016
10/6/2016
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
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Non-Qualified Stock Option Award
Agreement
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Performance Unit Award Agreement for
Section 16 Officers
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Performance Unit Award Agreement for
Section 16 Officers
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Initial CEO Option Grant Agreement
2
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-Q
10.1
5/7/2014
10-Q
10.2
5/7/2014
10-Q
10.1
11/6/2013
Marathon Oil Corporation 2012 Incentive Compensation Plan
DEF 14A
App. III
8-K
10.1
3/8/2012
8/1/2014
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
10.5
Filing Date
2/22/2013
Form
10-K
10-K
10.6
2/22/2013
10-K
10.7
2/22/2013
10-K
10.8
2/22/2013
10-K
10.9
2/22/2013
10-K
10.10
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
10.26
2/26/2010
10-K
10-K
10-K
10-K
10-K
10-K
10.9
10.29
2/26/2010
2/24/2017
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
10.19†
10.20†
10.21†
10.22†
10.23†
10.24†
10.25†
10.26†
10.27†
10.28†
10.29†
10.30†
10.31†
10.32†
10.33†*
10.34†
10.35†
10.36
12.1*
21.1*
23.1*
23.2*
23.3*
Exhibit Description
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)
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers (3-year cliff vesting)
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Restricted Stock Award Agreement for
Officers (3-year cliff vesting)
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Restricted Stock Award Agreement for
Section 16 Officers (3-year prorata vesting)
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Restricted Stock 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
Form of Marathon Oil Corporation 2007 Incentive
Compensation Plan Nonqualified Stock Option Award
Agreement for Section 16 Officers
Marathon Oil Corporation 2003 Incentive Compensation Plan
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 1,
2018)
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
Computation of Ratio of Earnings to Fixed Charges
List of Significant Subsidiaries
Consent of Independent Registered Public Accounting Firm
Consent of Independent Registered Public Accounting Firm
Consent of GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists
3
Incorporated by Reference (File No.
001-05153, unless otherwise indicated)
Exhibit
Filing Date
Form
10-K
99.1
2/25/2016
10-K
99.3
2/24/2017
10-K
99.4
2/24/2017
10-K
99.6
2/24/2017
Exhibit
Number
23.4*
23.5*
31.1*
31.2*
32.1*
32.2*
99.1
99.2*
99.3*
99.4*
99.5
99.6
99.7*
99.8
Exhibit Description
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
Report of GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists for 2015
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2016
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2016
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2016
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2016
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2015
Summary report performed by Netherland, Sewell &
Associates, Inc., independent petroleum engineers and
geologists for 2016
Summary report performed by Netherland, Sewell &
Associates, Inc., independent petroleum engineers and
geologists for 2015
99.9*
101.INS*
Alba Plant, LLC audited financial statements as of December
31, 2017
XBRL Instance Document
101.SCH*
XBRL Taxonomy Extension Schema
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase
101.LAB*
XBRL Taxonomy Extension Label Linkbase
101.DEF*
XBRL Taxonomy Extension Definition Linkbase
*
†
Filed herewith.
Management contract or compensatory plan or arrangement.
4
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
Zach Dailey, VP Investor Relations
+1 713-296-4140
Notice of Annual Meeting
The 2018 Annual Meeting of Stockholders will be held in
Houston, Texas, on May 30, 2018.
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
Dividends
Dividends on common stock, as declared by the board of
directors, are normally paid on the 10th day of March, June,
September and December.
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 2016 Annual Report
(the “2016 Peer Group”), and the new Peer Group Index that
replaces it (the “2017 Peer Group”). In order to reflect a peer
group more comparable in size and operations, the 2017 Peer
Group Index reflects the removal of ConocoPhillips Co. and
Occidental Petroleum Corporation, and the addition of Continental
Resources, Inc. 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 2017 Peer Group
Index is comprised of Anadarko Petroleum Corporation, Apache
Corporation, Chesapeake Energy Corporation, Continental
Resources, Inc., Devon Energy Corporation, Encana Corp., EOG
Resources, Inc., Hess Corporation, Murphy Oil Corporation, Noble
Energy, Inc., and Pioneer Natural Resources Company.
Comparison of Cumulative Total Return on $100
Invested in Marathon Oil Common Stock on December 31, 2012
vs.
*S&P 500 and Peer Group Index
250
200
150
100
50
0
Dec 12
Dec 13
Dec 14
Dec 15
Dec 16
Dec 17
MRO
S&P 500
2016 Peer Group Index
2017 Peer Group Index
*Total return assumes reinvestment of dividends
Forward-Looking Statements
This letter to stockholders 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 2018 capital development program
and the allocation thereof; returns, cash flow per debt adjusted share, cash flow, margins and asset quality.
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, natural gas and synthetic crude oil and the resulting impact on price; changes in expected
reserve or production levels; changes in political or economic conditions in the jurisdictions in which we operate, including
changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; risks
relating to our hedging activities; capital available for exploration and development; drilling and operating risks; well production
timing; 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, acts of war or terrorist acts and the governmental or military response thereto; cyber-attacks; changes in safety, health,
environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-
looking statements and challenges and uncertainties described in the Company’s 2017 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.