Dear Fellow Stockholders,
In 2015, Marathon Oil was proactive in taking the necessary actions to address the transition to a much lower
commodity price environment, while still advancing our U.S. resource plays. Reducing capital spending, lowering
production and general and administrative costs, enhancing productivity and progressing non-core asset sales
allowed us to be flexible and adapt as business conditions changed.
With a focus on the elements of our business we can control, we lowered production expenses by approximately
24 percent year over year. We also reduced our workforce by approximately 700 people, or more than 20
percent, which will result in annualized savings of approximately $160 million. Late last year, we announced a
quarterly dividend reduction of more than 75 percent to $0.05 per share to address the uncertain commodity
price environment and prioritize balance sheet protection, a move that is expected to increase our annual free
cash flow by more than $425 million. We expect to capture the full benefits of these cost reductions throughout
2016.
Production exceeded targets on lower capital program
In 2015, our capital program of $3 billion was 50 percent less than the prior year and $500 million below our
original target. Despite this reduction, we exceeded our yearly production targets for both total Company and
the U.S. resource plays. Total Company production available for sale, excluding Libya, increased 8 percent to
an average of 431,000 net barrels of oil equivalent (boe) per day in 2015. The primary driver was a 21 percent
production increase in our U.S. resource plays over the same period.
Cost-effective reserve replacement
Last year, we achieved an organic reserve replacement ratio of 157 percent, excluding revisions and dispositions,
at a competitive drillbit finding and development cost of $12 per boe. Our net proved reserves remain at
approximately 2.2 billion boe, of which 72 percent were proved developed. Among our peers, Marathon Oil is one
of the most focused on liquids, which represented more than 80 percent of 2015 reserves.
Capturing operating and capital efficiencies
Our 2015 operational results reflected consistent execution, high operational availability and more than $350
million in drilling and completions cost savings from ongoing internal efficiency and commercial improvements.
For example, drilling efficiency improved across U.S. resource plays, with Eagle Ford average spud to total depth
of just nine days in the fourth quarter of 2015 compared to 12 days in the year ago quarter. Both Eagle Ford
and Bakken have increased well productivity every year since 2011 through technology application, extensive
reservoir modeling, optimization of completion designs and improved artificial lift. Fourth quarter North America
E&P production costs were $6.91 per boe, down 28 percent from the year-ago period, with full-year North
America E&P unit production costs of $7.38 per boe.
Ongoing portfolio management
In 2015, we closed or announced non-core asset sales of more than $300 million, excluding closing adjustments,
in the Gulf of Mexico, East Texas, North Louisiana and Wilburton, Oklahoma, as well as our East Africa exploration
acreage. Based on announced transactions and progress on remaining non-core asset divestitures, we’ve
increased our target from $500 million to a range of $750 million to $1 billion.
Capital discipline in 2016
Our $1.4 billion 2016 capital program reflects the current challenging environment and our clear objective of
balance sheet protection. This program – which is more than 50 percent lower than last year and 75 percent
below 2014 – is designed to maximize capital allocation to the short-cycle investments in our U.S. resource plays,
complete long-cycle projects that contribute production and minimize spend on conventional exploration. Given
lower capital, reduced activity levels and divestitures, we expect total Company production to decline 6 to 8
percent from last year.
About 70 percent of the capital program will be directed to our U.S. resource plays in the Eagle Ford, STACK/
SCOOP and Bakken to maintain execution efficiency, protect high-value term leases and focus on the highest
returns. Across the remainder of the portfolio, several long-cycle projects will be completed in 2016 and
contribute to production. These include our operated compression project in Equatorial Guinea, the outside-
operated Gunflint development in the Gulf of Mexico and the outside-operated Atrush block in the Kurdistan
Region of Iraq. Capital allocated to our outside-operated Oil Sands Mining project and for conventional
exploration will be down materially from past years.
Committed to balance sheet protection and delivering value through the cycle
Marathon Oil is committed to continuing the momentum we achieved last year in lowering our cost structure,
enhancing operational productivity and progressing non-core asset sales.
Input from our board of directors guides Marathon Oil’s long-term success, and during the year, we were pleased
to welcome Gaurdie E. Banister, Jr., to our board. Gaurdie brings a wealth of insights gained from more than 35
years of global E&P experience, including eight years as chief executive officer of Aera Energy. We look forward
to working with him to continue to strengthen the Company. We also offer our thanks to Pierre Brondeau for his
service on our board of directors.
Although 2015 was a year of change for the industry, Marathon Oil employees dedicated themselves to executing
our plans, delivering results and Living Our Values. We thank them for protecting our license to operate every
day and for their ongoing efforts to position the Company to manage through the cycle.
On behalf of the board of directors, we thank our stockholders for the trust you have placed in our management
team as we continue transforming Marathon Oil into a premier independent E&P focused on the U.S. resource
plays.
Respectfully,
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, 2015
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, or a smaller reporting company. See
definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
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, 2015: $17,916 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 676,886,641 shares of Marathon Oil Corporation Common Stock outstanding as of February 15, 2016.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2016 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
PART II
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4. Mine Safety Disclosures
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
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
Item 14.
Principal Accountant Fees and Services
PART III
PART IV
Item 15. Exhibits, Financial Statement Schedules
SIGNATURES
5
25
34
34
34
34
35
36
37
60
63
118
118
118
119
119
119
120
120
121
122
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 hold 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 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.
Downstream business – The refining, marketing and transportation ("RM&T") operations, spun-off on June 30, 2011 and
treated as discontinued operations.
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.
EIA – United States Energy Information Agency.
EPA – United States Environmental Protection Agency.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously
found to be productive in another reservoir.
FASB – Financial Accounting Standards Board.
FPSO - Floating production, storage and offloading vessel.
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, synthetic 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 downstream business.
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.
1
mmcfd – Million cubic feet per day.
mmta – Million metric tonnes per annum.
MPC - Marathon Petroleum Corporation – The separate independent company which now owns and operates the downstream
business.
mtd – Thousand 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, that 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 and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
Proved reserves – Proved crude oil and condensate, NGLs, natural gas and 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 or through installed extraction equipment and
infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. 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
producibility at greater distances.
PSC – Production sharing contract.
Quest CCS – Quest Carbon Capture and Storage project at the AOSP in Alberta, Canada.
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.
SAGE – United Kingdom Scottish Area Gas Evacuation system composed of a pipeline and processing terminal.
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).
2
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.
U.S. GAAP – Accounting principles generally accepted in the U.S.
WCS – Western Canadian Select, an oil index benchmark price with monthly pricing based upon average WTI adjusted for
differentials unique to western Canada.
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 interest 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, workforce reductions and expected savings, cost
reductions, non-core asset sales, and financial flexibility; our ability to successfully effect those strategies and the expected
timing and results thereof; our 2016 Capital 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 ability and strategies
to manage through the lower commodity price cycle; 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, 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 pricing and supply/demand levels for crude oil and condensate, NGLs,
natural gas and synthetic crude oil;
changes in expected reserve or production levels;
changes in political or economic conditions in key operating markets, including international markets;
capital available for exploration and development;
•
• well production timing;
•
•
•
•
•
•
•
•
availability of drilling rigs, materials and labor;
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 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 is an independent global exploration and production company based in Houston, Texas, with
operations in North America, Europe and Africa. Our corporate headquarters are located at 5555 San Felipe Street, Houston,
Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our three reportable operating segments is organized
based upon both geographic location and the nature of the products and services it offers.
• North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North
•
America;
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of
North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in
E.G.; and
• Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades
the bitumen to produce and market synthetic crude oil and vacuum gas oil.
We were incorporated in 2001. On June 30, 2011, we completed the spin-off of our downstream business, creating two
independent energy companies: Marathon Oil and MPC.
Strategy and Results Summary
Marathon Oil’s strategy is to safely and sustainably deliver value by investing in low cost, liquids-rich projects with a focus
on risk-adjusted rates of return. We are focused in the high quality core of three premier unconventional resource plays in the
U.S.: the Eagle Ford, Bakken and Oklahoma Resource Basins. Our strategy for our operated conventional producing assets in
E.G., the U.K. and the U.S. is to maximize value and cash flow to provide flexibility to invest in the shorter cycle opportunities
in the U.S. resource plays. Our conventional exploration program is currently limited to existing commitments in the Gulf of
Mexico and Gabon. Our strategy is guided by the following seven strategic imperatives ("SI7"):
1. Living Our Values
2.
Investing in Our People
3. Continuous Improvement in Operational and Capital Efficiency
4. Driving Profitable and Sustainable Growth
5. Rigorous Portfolio Management
6. Quality and Material Resource Capture
7. Delivering Long-Term Shareholder Value
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the
amount of capital available to reinvest into our business. The low pricing environment has presented several challenges for us
and our industry. We responded to the lower commodity prices in a number of ways:
• Reduced our 2015 Capital Program by approximately 50% from the prior year, down to $3 billion
• Established our 2016 Capital Program at $1.4 billion
• Exercised cost discipline, significantly reducing drilling and completion, production and general and administrative
costs
• Drove sustainable operational efficiency gains in the U.S. unconventional resource plays
•
•
Scaled back our conventional exploration program to focus on our U.S. unconventional resources plays
Increased our target for non-core asset sales, now $750 million to $1 billion, up from our previous goal of $500 million
Closed over $300 million of non-core asset sales (excluding closing adjustments)
•
Protected our liquidity and capital structure:
Issued $2 billion aggregate principal amount of unsecured senior notes ($1 billion of which was used to repay
the 0.90% senior notes that matured in November 2015)
Increased the capacity of the revolving credit facility from $2.5 billion to $3.0 billion while also extending the
maturity date an additional year to May 2020
Decreased our quarterly dividend from $0.21 to $0.05 per share, saving approximately $425 million of cash
on an annualized basis
5
In 2015, we continued to focus on the U.S. unconventional resource plays. We progressed co-development in the Eagle
Ford, further delineated Austin Chalk in the Eagle Ford along with SCOOP/STACK in the Oklahoma Resource Basins and
improved overall competitiveness in the Bakken with cost reductions and enhanced completions. Our U.S. operations added 73
mmboe proved reserves in 2015, excluding acquisitions, dispositions and production, amounting to an increase of 107% over
the prior year's ending balance.
Net sales volumes from continuing operations increased by 6% to 438 mboed in 2015 from 415 mboed in 2014. Volumes
from our three U.S. resource plays totaled 218 mboed, an increase of 20% from 181 mboed in 2014. For the total company, we
ended 2015 with proved reserves of approximately 2,163 mmboe as compared to 2,198 mmboe at the end of 2014.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook, for a more
detailed discussion of our operating results, cash flows and outlook, including the 2016 Capital Program.
The map below shows the locations of our worldwide operations.
Segment and Geographic Information
For operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data –
Note 7 to the consolidated financial statements.
In the following discussion regarding our North America E&P, International E&P and Oil Sands Mining segments,
references to net wells, acres, sales or investment indicate our ownership interest or share, as the context requires.
North America E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in the U.S. and Canada. Our primary
focus in the North America E&P segment is concentrated within our unconventional resource plays. The following tables
provide additional detail regarding net sales volumes, sales mix and operated drilling activity:
6
Net Sales Volumes
Equivalent Barrels (mboed)
Eagle Ford
Oklahoma Resource Basins
Bakken
Other North America (a)
Total North America E&P (mboed)
(a)
Includes Gulf of Mexico and other conventional onshore U.S. production
2015
Increase
(Decrease)
2014
Increase
(Decrease)
2013
134
25
59
51
269
20 %
39 %
16 %
(11)%
13 %
112
18
51
57
238
38 %
29 %
31 %
(15)%
18 %
Sales Mix - U.S. Resource Plays - 2015
Eagle Ford
Oklahoma
Resource
Basins
Bakken
Crude oil and condensate
Natural gas liquids
Natural gas
Drilling Activity - U.S. Resource Plays
Gross Operated
Eagle Ford:
Wells drilled to total depth
Wells brought to sales
Oklahoma Resource Basins:
Wells drilled to total depth
Wells brought to sales
Bakken:
Wells drilled to total depth
Wells brought to sales
60%
19%
21%
19%
28%
53%
2015
2014
2013
251
276
20
21
35
56
360
310
19
18
83
69
81
14
39
67
201
87%
7%
6%
299
307
10
9
76
77
Eagle Ford - As of December 31, 2015, we had approximately 153,000 net acres in the Eagle Ford in south Texas and
1,236 gross (911 net) operated producing wells, where we have been operating since 2011.
Of the 276 gross wells brought to sales in 2015, 56 were in the Austin Chalk, 28 were in the Upper Eagle Ford and 192
were in the Lower Eagle Ford. Of the 310 gross wells brought to sales in 2014, 22 were in the Austin Chalk and four were in
the Upper Eagle Ford. Our 2015 average spud-to-TD time was 11 days compared to 13 days in 2014. Our high-density pad
drilling continues to average approximately four wells per pad in 2015. The continued focus on stimulation design has
contributed to incremental improvements in well performance across our area of activity.
During 2015, we continued evaluation of the Austin Chalk formation and began delineation of Upper Eagle Ford across our
acreage position in south Texas, with a total of 22,000 Austin Chalk acres and 16,500 Upper Eagle Ford acres now delineated.
The mix of crude oil and condensate, NGLs and natural gas from the Austin Chalk wells is similar to Eagle Ford condensate
wells. Co-development of the Austin Chalk, Upper and Lower Eagle Ford horizons will leverage the infrastructure investments
we have made to support production growth across the Eagle Ford operating area.
We operate approximately 800 miles of gathering pipeline in the Eagle Ford area. We now have 32 central gathering and
treating facilities, with aggregate capacity of more than 475 mboed. 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 of south Texas.
In late 2015, we connected to a newly constructed third-party liquids pipeline, which allowed us to increase the amount of
our Eagle Ford production transported by pipeline to 90% at year-end, up from an average of 70% during 2014. The ability to
transport more barrels by pipeline enables us to improve/optimize price realizations, reduce costs, improve reliability and lessen
our environmental footprint.
Approximately 42% of our 2016 Capital Program, $600 million, is allocated to the Eagle Ford. We expect drilling activity
to average five rigs in 2016. Our drilling plans for 2016 include drilling 91 - 96 net wells (150 - 160 gross, of which we will
operate 134 - 141). We anticipate bringing 124 - 132 gross operated wells to sales during 2016.
Oklahoma Resource Basins – Our primary focus in 2016 will be in the SCOOP and STACK areas. In the SCOOP and
STACK areas we hold approximately 265,000 net acres with rights to the Woodford, Springer, Meramec, Granite Wash and
7
other Pennsylvanian and Mississippian plays. This includes 8,000 net acres added in the Oklahoma Resource Basins, primarily
in the STACK Meramec play during 2015.
Approximately 90% of our SCOOP acreage is held by production. In the SCOOP Woodford, we delineated over 70% of
our acreage. We estimate the SCOOP Springer has a high oil yield that is about 85% liquids. We believe about 80% of our
acreage in STACK has the potential for co-development of multiple horizons. About 67,000 STACK Woodford acres are
delineated while approximately 42,000 acres of STACK Meramec acreage is delineated.
Approximately 14% of our 2016 Capital Program, $204 million, is allocated to the Oklahoma Resource Basins, which will
support two rigs and lease retention in the STACK and delineation of the SCOOP Springer and Meramec. Our drilling plans for
the Oklahoma Resource Basins in 2016 call for drilling and completing 23 - 28 net wells (65 - 75 gross, of which 24 - 27 are
company operated wells). We anticipate bringing 20 - 22 gross operated wells to sales during 2016.
Bakken – We hold approximately 277,000 net acres in the Bakken shale oil play in North Dakota and eastern Montana,
where we have been operating since 2006. We continue to see improvement in efficiency and well performance through
optimizing completion techniques. We successfully completed a 55-well enhanced completion trial program that began in late
2014 and continued through 2015. We will continue executing and evaluating enhanced completion designs, including
increased stage counts, high proppant volumes and fluid types as opportunities arise in 2016. Our large scale water gathering
system is currently handling over 50% of our produced water. With a second phase expected to be fully operational in the
second half of 2016, we anticipate this system will manage 80% of produced water by year end.
Our time to drill a well averaged 15 days spud-to-TD in 2015 compared to 17 days in 2014. We recompleted 11 wells
during 2015. In efforts to optimize price realizations, we sell our production in local North Dakota markets and to select
purchasers who may elect to transport outside the state.
Approximately 13% of our 2016 Capital Program, $193 million, is allocated to the Bakken, which will support one rig in
2016. Our 2016 Bakken program includes plans to drill 10 - 12 net wells (45 - 55 gross, of which we will operate 8 - 10). We
anticipate bringing 13 - 15 gross operated wells to sales during 2016.
Other North America
During 2015, we further emphasized our focus on the U.S. unconventional resource plays, continued to maximize cash
generation from our conventional assets and continued to dispose of non-core assets. In August 2015, we closed the sale of our
East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. In December 2015, we closed the sale of our
operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius field in the
Gulf of Mexico. In February 2016, we closed the sale of our non-operated producing interests in the Neptune field in the Gulf
of Mexico. These assets collectively produced approximately 14 mboed in 2015.
Other North America consists primarily of onshore production operations in Wyoming and development activities in the
Gulf of Mexico. In the Gulf, development work continues in the Gunflint field located on Mississippi Canyon Blocks 948, 949,
992 (N/2) and 993 (N/2). The development wells were completed in 2015. First oil is expected in mid-2016 after the
completion of work at the third-party Gulfstar 1 host facility. We hold an 18% non-operated working interest in the Gunflint
field.
A deepwater oil discovery on the Shenandoah prospect, located on Walker Ridge Block 51, was drilled in 2009. We own a
10% non-operated working interest in this prospect. The first appraisal well on the Shenandoah prospect reached total depth in
2013 and was successful. The operator drilled a second appraisal well in 2014, which was unsuccessful. A third appraisal well
was spud in 2015, and was successfully sidetracked, logged and cored, finding more than 620 feet of net oil pay. A fourth
appraisal well is expected to be spud in the first quarter of 2016.
Wyoming - We have ongoing waterflood and enhanced oil recovery projects in the mature Big Horn and Wind River
Basins. Marathon is the third largest oil producer in the state of Wyoming. We also have conventional natural gas operations in
the Greater Green River Basin.
Our Wyoming net sales averaged 17 mbbld of liquid hydrocarbons and 4 mmcfd of natural gas, or 17 mboed, during 2015
compared to 18 mboed in 2014. In addition, Marathon owns the 420-mile Red Butte Pipeline which connects oil fields in the
Big Horn Basin to both the Silvertip Station on the Montana/Wyoming state line and to alternate outlets in Casper, Wyoming.
8
North America E&P--Exploration
In September 2015, we announced our intention to scale back our conventional exploration program. Our 2016 Capital
Program includes $15 million for conventional exploration. No conventional exploration wells are planned in 2016. Our
Capital Program is limited to existing commitments in the Gulf of Mexico. We continue to evaluate options for utilization of
our remaining commitments on the Maersk Valiant drillship. The rig is currently being operated by our rig share partner, and
we anticipate the rig to be available for our use in early 2017.
The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of 2015 and
reached total depth in the fourth quarter. The well did encounter the lower tertiary target interval. The well was plugged and
abandoned, with well costs charged to dry well expense, and the rig was released with no further activity planned on the block.
We hold a 58% operated working interest in this prospect.
We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which could be
developed using in-situ methods of extraction. These leases cover approximately 142,000 gross (54,000 net) acres in four
project areas: Namur, in which we hold a 70% operated interest; Birchwood, in which we hold a 100% operated interest; Ells
River, in which we hold a 20% non-operated interest; and Saleski in which we hold a 33% non-operated interest. During 2015,
in connection with our decision to scale back our conventional exploration program, and also after further evaluation of the
estimated recoverable resources and our development plans at Birchwood, Ells River and Namur, we impaired the remaining
net book values of these in-situ properties.
International E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in E.G., Gabon, the Kurdistan Region
of Iraq, Libya and the U.K. We include the results of our natural gas liquefaction operations and methanol production
operations in E.G. in our International E&P segment. The following table provides net sales volumes for our significant
operational areas within this segment:
Increase
(Decrease)
Increase
(Decrease)
2015
Net Sales Volumes
Equivalent Barrels (mboed)
Equatorial Guinea
United Kingdom (a)
Libya
Total International E&P (mboed)
Net Sales Volumes of Equity Method Investees
LNG (mtd)
Methanol (mtd)
(a) Includes natural gas acquired for injection and subsequent resale of 8 mmcfd, 6 mmcfd and 7 mmcfd for 2015, 2014, and 2013.
(7)%
19 %
(100)%
(9)%
104
16
7
127
97
19
—
116
(10)%
(14)%
5,884
937
6,535
1,092
2014
2013
107
20
28
155
6,548
1,249
(3)%
(20)%
(75)%
(18)%
— %
(13)%
Africa
Equatorial Guinea – Production – We own a 63% operated working interest under a PSC in the Alba field which is
offshore E.G. Operational availability from our company-operated facilities averaged approximately 97% in 2015. In the third
quarter of 2015, production was increased as the Alba C21 development well came online with higher than expected liquid
yields, in combination with a successful well intervention program on five existing Alba wells. In January 2016, we completed
the installation of an offshore compression platform which is expected to start up mid-2016 following completion of hookup
and commissioning activities. The compression project was designed to maintain the production plateau two additional years
and extend field life up to eight years.
Equatorial Guinea – Gas Processing – We own a 52% interest in Alba Plant LLC, an equity method investee, that operates
an onshore LPG processing plant located on Bioko Island. Alba field natural gas is processed by the LPG plant. Under a long-
term contract at a fixed price per btu, 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 of which are accounted for as equity method investments.
EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These
facilities allow us to monetize natural gas reserves from the Alba field.
EGHoldings' 3.7 mmta LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement
through 2023. The purchaser under the agreement 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 3.6 mmta in 2015.
9
AMPCO had gross sales totaling 760 mt in 2015. Production from the plant is used to supply customers in Europe and the
U.S.
Libya – We hold a 16% non-operated working interest in the Waha concessions, which encompass almost 13 million gross
acres located in the Sirte Basin of eastern Libya, where civil and political unrest continues to interrupt our production
operations. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and
although temporarily re-opened during the second half of 2014, production remains shut-in through early 2016. Considerable
uncertainty remains around the timing of future production and sales levels. We and our partners in the Waha concessions
continue to assess the situation and the condition of our assets in Libya. See Item 8. Financial Statements and Supplementary
Data – Note 12 to the consolidated financial statements for additional information about our Libya operations.
Other International
United Kingdom – Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the operator
and have a 42% working interest in the South, Central, North and West Brae fields and a 39% working interest in the East Brae
field. The Brae Alpha platform and facilities host the South, Central and West Brae fields. The North Brae and East Brae fields
are natural gas condensate fields which are produced via the Brae Bravo and the East Brae platforms, respectively. The East
Brae platform also hosts the nearby Braemar field in which we have a 28% working interest. During the second quarter of 2015,
we completed the final three wells of a five-well Brae infill drilling program that began in 2014.
The strategic location of the Brae platforms, along with pipeline and onshore infrastructure, has generated third-party
processing and transportation business since 1986. Currently, the operators of 31 third-party fields are contracted to use the
Brae system and 72 mboed are being processed or transported through the Brae infrastructure. In addition to generating
processing and pipeline tariff revenue, this third-party business optimizes infrastructure usage.
The working interest owners of the Brae area producing assets collectively own a 50% non-operated interest in the SAGE
system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl area, and has a total wet natural
gas capacity of 1.1 bcf per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE
pipeline as well as approximately 0.3 bcf per day of third-party natural gas.
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. The export of
Foinaven liquid hydrocarbons is via shuttle tanker from an FPSO to market. All natural gas sales are to the non-operated
Magnus platform for use as injection gas.
Kurdistan Region of Iraq – In aggregate, we have approximately 109,000 net acres in the Kurdistan Region of Iraq. We
have a 45% operated working interest in the Harir block located northeast of Erbil. We also have non-operated interests in two
blocks located north-northwest of Erbil: Atrush with 15% working interest and Sarsang with 20% working interest.
On the non-operated Atrush block, following the successful appraisal program and a declaration of commerciality, the
Kurdistan Ministry of Natural Resources approved a plan for field development in September 2013. The development project
consists of drilling four production wells and constructing a central processing facility in Phase 1 which provides for a 25-year
production period. We expect first production in late 2016 with estimated initial gross production of approximately 30 mbbld
of oil. Subject to further drilling and testing results, and partner and government approvals, a potential Phase 2 development
could add an additional gross 30 mbbld facility.
On the non-operated Sarsang block, the Swara Tika discovery was declared commercial in May 2014 and a field
development plan was filed in June 2014. The plan was approved by the Kurdistan Ministry of Natural Resources in the fourth
quarter of 2015. The first producing well came online in 2014 and the second producing well came online in December 2015.
In 2016, an additional well is planned to come on-line. As the development plan progresses, we expect to increase production
after 2016.
International E&P Exploration
In September 2015, we announced our intention to scale back our conventional exploration program. Our 2016 Capital
Program includes $16 million for conventional exploration. No conventional exploration wells are planned in 2016. Our
Capital Program is limited to existing commitments in Gabon.
Equatorial Guinea – Exploration – We hold a 63% operated working interest in the Deep Luba discovery on the Alba
Block and an 80% operated working interest in the Corona well on Block D. We plan to develop Block D through a unitization
with the Alba field. Negotiations have been substantially completed and approval is expected in 2016. We also have an 80%
operated working interest in exploratory Block A-12 offshore Bioko Island, located immediately west of our operated Alba
Field.
10
Gabon – Exploration – We hold a 21.25% non-operated working interest in the Diaba License G4-223 and its related
permit offshore Gabon, which covers approximately 2.2 million gross (477,000 net) acres. Multiple additional pre-salt
prospects have been identified on this License.
In August 2014, we signed an exploration and production sharing contract for Gabon offshore Block G13, which was
subsequently re-named Tchicuate. The block, which is located in the pre-salt play offshore Gabon, encompasses 277,000 acres.
The seismic program was completed during 2015 and processing will occur through 2016. We hold a 100% participating
interest and operatorship in the block. In the event of development, the Republic of Gabon will assume a 20% financed interest
in the contract upon commencement of production. The State holds additional rights to participate in the block in the future as
a co-investor.
Kurdistan Region of Iraq – During 2015, in connection with our decision to scale back our conventional exploration
program, we impaired our investment in the operated Harir block.
International E&P Disposition
In the third quarter of 2015, we entered into an agreement to sell our East Africa exploration acreage in Ethiopia and
Kenya. The Kenya transaction closed in February 2016 and the Ethiopia transaction is expected to close during the first quarter
of 2016. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for
additional information about this disposition.
Oil Sands Mining Segment
We hold a 20% non-operated interest in the AOSP, an oil sands mining and upgrading joint venture located in Alberta,
Canada. Other JV partners include Shell Canada Limited with a 60% ownership interest and Chevron Canada Limited with a
20% ownership interest. Shell Canada Limited operates the joint venture, which produces bitumen from oil sands deposits in
the Athabasca region utilizing mining techniques and upgrades the bitumen into synthetic crude oils and vacuum gas oil.
The AOSP’s mining and extraction assets are located near Fort McMurray, Alberta, and include the Muskeg River and the
Jackpine mines. Gross design capacity of the combined mines is 255,000 (51,000 net) barrels of bitumen per day. The AOSP
operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into
synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through a series
of primary crushers and rotary breakers for particle size reduction. The particles are combined with hot water to create slurry.
The slurry is hydro-transported to a primary separation vessel where it separates into sand, clay and bitumen-rich froth.
A solvent is added to the bitumen froth to separate out the remaining solids, water and heavy asphaltenes. The solvent washes
the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixture of solvent
and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300-mile Corridor
Pipeline.
The AOSP's Scotford upgrader is located at Fort Saskatchewan, northeast of Edmonton, Alberta. The bitumen is upgraded
at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules
into lighter products. Blendstocks acquired from outside sources are utilized in the production of our saleable products. The
upgrader produces synthetic crude oils and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a
long-term contract at market-related prices and the other products are sold in the marketplace.
As of December 31, 2015, we own or have rights to participate in developed and undeveloped surface mineable leases
totaling approximately 159,000 gross (32,000 net) acres. The underlying developed leases are held for the duration of the
project, with royalties payable to the province of Alberta. Synthetic crude oil sales volumes for 2015 averaged 53 mbbld and
net-of-royalty production was 45 mbbld.
The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs
incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. As
average price realizations are typically at a discount to WTI, the fixed operating cost structure for Oil Sands Mining will not
fully track the price realization. Significant cost improvement efforts were employed in 2015 resulting in a material reduction
to the production cost structure. See Item 7. Consolidated Results of Operations: 2015 compared to 2014 for additional detail
on production expenses.
The governments of Alberta and Canada agreed to partially fund Quest CCS. Construction began in 2012 and was
completed in February 2015. Government funding commenced in 2012 and continued as milestones were achieved during the
development, construction and operating phases of the project. Quest CCS was successfully completed and commissioned in
the fourth quarter of 2015.
11
Productive and Drilling Wells
For our North America E&P and International E&P segments, the following table sets forth gross and net productive wells
and service wells as of December 31, 2015, 2014 and 2013 and drilling wells as of December 31, 2015.
Productive Wells(a)
Oil
Natural Gas
Gross
Net
Gross
Net
Service Wells
Net
Gross
Drilling Wells
Net
Gross
29
—
4
4
1
34
12
—
1
1
—
13
2015
U.S.
E.G.
Other Africa
Total Africa
Other International
Total
2014
U.S.
E.G.
Other Africa
Total Africa
Other International
Total
2013
U.S.
E.G.
Other Africa
Total Africa
Other International
Total
7,198
—
1,071
1,071
59
8,328
7,058
—
1,071
1,071
55
8,184
6,632
—
1,064
1,064
56
7,752
2,878
—
175
175
21
3,074
2,919
—
175
175
20
3,114
2,568
—
174
174
21
2,763
1,796
17
7
24
39
1,859
2,246
16
7
23
39
2,308
2,763
16
7
23
40
2,826
750
11
1
12
16
778
1,023
11
1
12
16
1,051
1,482
11
1
12
16
1,510
2,727
2
94
96
24
2,847
2,638
2
94
96
24
2,758
2,349
2
94
96
25
2,470
747
1
16
17
8
772
760
1
16
17
8
785
744
1
16
17
9
770
(a) Of the gross productive wells, wells with multiple completions operated by us totaled 12, 31 and 31 as of December 31, 2015, 2014 and 2013.
Information on wells with multiple completions operated by others is unavailable to us.
12
Drilling Activity
For our North America E&P and International E&P segments, the following table sets forth, by geographic area, the
number of net productive and dry development and exploratory wells completed in each of the last three years.
Oil
Year Ended December 31, 2015
U.S.
Year Ended December 31, 2014
U.S.
Year Ended December 31, 2013
U.S.
E.G.
Other Africa
Total Africa
Other International
Total
E.G.
Other Africa
Total Africa
Other International
Total
E.G.
Other Africa
Total Africa
Other International
Total
Acreage
Development
Exploratory
Natural
Gas
Dry
Total
Oil
Natural
Gas
Dry
Total
Total
36
1
—
1
—
37
43
—
—
—
—
43
20
—
—
—
—
20
11
—
—
—
—
11
1
—
—
—
—
1
—
—
—
—
—
—
182
1
—
1
1
184
297
—
1
1
1
299
257
—
4
4
—
261
49
—
—
—
—
49
49
—
—
—
—
49
73
—
1
1
—
74
48
—
—
—
—
48
19
—
—
—
—
19
13
—
—
—
—
13
1
1
—
1
—
2
4
1
—
1
—
5
3
—
2
2
3
8
98
1
—
1
—
99
72
1
—
1
—
73
89
—
3
3
3
95
280
2
—
2
1
283
369
1
1
2
1
372
346
—
7
7
3
356
135
—
—
—
1
136
253
—
1
1
1
255
237
—
4
4
—
241
We believe we have satisfactory title to our North America 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 PSCs or exploration licenses.
The following table sets forth, by geographic area, the gross and net developed and undeveloped acreage held in our North
America E&P and International E&P segments as of December 31, 2015.
(In thousands)
U.S.
Canada
Total North America
E.G.
Other Africa
Total Africa
Other International
Total
Developed
Gross
Net
Undeveloped
Net
Gross
1,323
—
1,323
45
12,909
12,954
90
1,035
—
1,035
29
2,108
2,137
32
801
142
943
183
26,145
26,328
345
638
54
692
164
9,612
9,776
110
Developed and
Undeveloped
Net
Gross
2,124
142
2,266
228
39,054
39,282
435
1,673
54
1,727
193
11,720
11,913
142
14,367
3,204
27,616
10,578
41,983
13,782
13
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, undeveloped acreage listed in the table
below will expire over the next three years. We plan to continue the terms of certain of these licenses and concession areas or
retain leases through operational or administrative actions; however, the majority of the undeveloped acres associated with
Other Africa as listed in the table below pertains to our licenses in Ethiopia and Kenya, for which we executed agreements in
2015 to sell. The Kenya transaction closed in February 2016 and the Ethiopia transaction is expected to close in the first
quarter of 2016. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for
additional information about this disposition.
(In thousands)
U.S.
E.G.
Other Africa
Total Africa
Other International
Total
Net Undeveloped Acres Expiring
Year Ended December 31,
2017
2018
2016
68
—
189
189
—
257
89
92
4,352
4,444
—
4,533
128
36
854
890
—
1,018
14
Reserves
Estimated Reserve Quantities
Reserves are 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. We closed the sale of our East Texas/North Louisiana/Wilburton assets in the third quarter of 2015 and part of
our Gulf of Mexico business in the fourth quarter of 2015. Additionally, we closed the sale of our Angola assets and our
Norway business in 2014, and both are represented as discontinued operations ("Disc Ops") for periods presented.
Approximately 77% of our proved reserves are located in OECD countries.
Our December 31, 2015 proved reserves were calculated using the unweighted average of closing prices nearest to the first
day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing of benchmark
prices as well as the unweighted average for the first two months of 2016:
WTI Crude oil
Henry Hub natural gas
Brent crude oil
Natural gas liquids
$
$
$
$
SEC Pricing 2015
2-month Average 2016
34.19
2.28
50.28 $
2.59 $
54.25 $
17.32 $
34.86
12.87
When determining the December 31, 2015 proved reserves for each property, the 2015 SEC prices listed above were
adjusted using price differentials that account for property-specific quality and location differences.
Beginning in the second half of 2014, the crude oil and natural gas benchmarks began to decline and these declines
continued through 2015 and into 2016. Commodity prices are likely to remain volatile based on global supply and demand and
could decline further. Sustained reduced commodity prices could have a material effect on the quantity and future cash flows of
our proved reserves.
Estimates of future cash flows associated with proved reserves are based on actual costs of developing and producing the
reserves as of the end of the year. The decline in commodity prices prompted a concerted effort to reduce the costs of
developing and producing reserves. Therefore, the impact of sustained reduced commodity prices on future cash flows will be
partially offset by the resulting lower costs to develop and produce reserves.
A sustained period of lower commodity prices could also result in additional decreases to our near term capital program
and deferrals of investment until prices improve. A shifting of capital expenditures into future periods beyond five years from
the initial proved reserve booking could potentially lead to a reduction in proved undeveloped reserves. See Item 1A. Risk
Factors for a further discussion of how a substantial extended decline in commodity prices could impact us.
As of December 31, 2015, total proved reserves declined 35 mmboe, primarily due to negative revisions in the U.S.
totaling 173 mmboe largely a result of reductions to our capital development program which deferred proved undeveloped
reserves beyond the 5-year plan, as well as routine production. This decline was partially offset by increased reserves from the
drilling programs in our U.S. unconventional shale plays totaling 246 mmboe as well as a positive revision of 67 mmboe in
OSM. The OSM revision was a consequence of technical reevaluation and lower royalty percentages due to lower realized
prices. Royalties paid in Canada are on a sliding scale; as the sales price of our synthetic crude oil decreases, our royalty rate
decreases. See Item 8. Financial Statements and Supplementary Data - Supplementary Information on Oil and Gas Producing
Activities for more information.
15
The following tables set forth estimated quantities of our proved crude oil and condensate, NGLs, natural gas and synthetic
crude oil reserves based upon an SEC pricing for periods ended December 31, 2015, 2014 and 2013.
December 31, 2015
Proved Developed Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved developed reserves
(mmboe)
Proved Undeveloped Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved undeveloped
reserves (mmboe)
Total Proved Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved reserves (mmboe)
December 31, 2014
Proved Developed Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved developed reserves
(mmboe)
Proved Undeveloped Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved undeveloped
reserves (mmboe)
Total Proved Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved reserves (mmboe)
327
92
640
—
526
253
80
511
—
418
580
172
—
—
—
—
—
—
—
North America
Africa
U.S. Canada
Total E.G. Other
Total
Other
Int'l
Cont
Ops
Disc
Ops
Total
—
—
—
698
327
92
640
698
25
12
552
—
173
—
94
—
198
12
646
—
16
—
11
—
541
104
1,297
698
—
541
—
104
— 1,297
698
—
698
1,224
129
189
318
18
1,560
— 1,560
253
80
511
—
27
16
538
—
28
—
112
—
55
16
650
—
418
132
46
178
580
172
52
28
1,090
—
261
201
—
206
—
235
253
28
1,296
—
496
1,151
—
944
— 1,151
698
698
698
1,642
6
—
4
—
7
22
—
15
—
25
314
96
1,165
—
603
855
200
2,462
698
2,163
314
—
96
—
— 1,165
—
—
—
—
—
603
855
200
— 2,462
698
—
— 2,163
North America
Africa
U.S. Canada
Total E.G. Other
Total
Other
Int'l
Cont
Ops
Disc
Ops
Total
294
68
575
—
458
340
93
569
—
528
634
161
1,144
—
986
—
—
—
644
294
68
575
644
644
1,102
—
—
—
4
4
340
93
569
4
532
30
15
664
—
155
27
15
541
—
133
634
—
—
161
— 1,144
648
1,634
648
648
57
30
1,205
—
288
16
175
—
94
—
191
33
—
115
—
205
15
758
—
346
60
15
656
—
52
185
208
—
209
—
243
265
30
1,414
—
531
19
—
17
—
518
83
1,350
644
518
—
—
83
— 1,350
644
—
22
1,470
— 1,470
10
1
5
—
11
29
1
22
—
33
410
109
1,230
4
410
—
—
109
— 1,230
4
—
728
—
728
928
192
2,580
648
2,198
928
—
—
192
— 2,580
—
648
— 2,198
December 31, 2013
Proved Developed Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved developed reserves
(mmboe)
Proved Undeveloped Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved undeveloped
reserves (mmboe)
Total Proved Reserves
Crude oil and condensate (mmbbl)
Natural gas liquids (mmbbl)
Natural gas (bcf)
Synthetic crude oil (mmbbl)
Total proved reserves (mmboe)
Preparation of Reserve Estimates
North America
Africa
U.S. Canada
Total E.G. Other
Total
Other
Int'l
Cont
Ops
Disc
Ops
241
51
540
—
382
256
68
485
—
405
497
119
1,025
—
787
—
—
—
674
241
51
540
674
674
1,056
—
—
—
6
6
256
68
485
6
411
37
18
823
—
193
27
16
497
—
125
497
—
—
119
— 1,025
680
680
1,467
680
64
34
1,320
—
318
176
—
95
—
192
39
—
110
—
57
215
—
205
—
249
213
18
918
—
385
66
16
607
—
182
279
34
1,525
—
567
19
1
21
—
23
6
—
7
—
8
25
1
28
—
31
473
70
1,479
674
1,464
328
84
1,099
6
601
801
154
2,578
680
2,065
77
—
20
—
80
14
—
73
—
26
91
—
93
—
106
Total
550
70
1,499
674
1,544
342
84
1,172
6
627
892
154
2,671
680
2,171
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate,
NGLs, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group,
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 engineers or
geoscientists who 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 Marathon Oil's QRE training course. All
QREs must complete a QRE refresher course at least once every three years. Our Corporate Reserves group screens all fields
with net proved reserves of 20 mmboe or greater, every year, to determine if a field review is required. Any change to proved
reserve estimates in excess of 1 mmboe on a total field basis, within a single month, must be approved by a Reserve
Coordinator.
Our Director of Corporate Reserves, who reports to our Vice President, Technology and Innovation, has a Bachelor of
Science degree in petroleum engineering and is a registered Professional Engineer in the State of Texas. In his 28 years with
Marathon Oil, he has held numerous engineering and management positions, including managing our OSM segment. He is a
member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council
for the University of Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Alberta, Canada,
third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The individual
responsible for the estimates of our synthetic crude oil reserves has 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,
2015, with 82% of our total proved reserves independently audited. We have established a tolerance level of +/- 10% such that
initial estimates by the third-party consultants for each field are accepted if they are within 10% of our internal estimates.
Should the third-party consultants’ initial analysis fail to reach our tolerance level, both parties 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 2015,
2014 or 2013.
17
During 2015, 2014 and 2013, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a certification of the prior year's
reserves 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. The senior technical advisor has over 35 years of practical experience in petroleum
geosciences, with over 15 years experience in the estimation and evaluation of reserves. The second team member has over 10
years of practical experience in petroleum engineering, with over five years experience in the estimation and evaluation of
reserves. Both are registered Professional Engineers in the State of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of the prior years' reserves of several of our fields in 2015,
2014 and 2013. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder
Scott has over 20 years of industry experience, having worked for a major international oil and gas company before joining
Ryder Scott. He is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional
Engineer in the State of Texas.
Changes in Proved Undeveloped Reserves
As of December 31, 2015, 603 mmboe of proved undeveloped reserves were reported, a decrease of 125 mmboe from
December 31, 2014. The following table shows changes in total proved undeveloped reserves for 2015:
(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
728
(223)
1
1
175
—
(79)
603
The revisions to previous estimates were largely due to a result of reductions to our capital development program which
deferred proved undeveloped reserves beyond the 5-year plan. A total of 139 mmboe was booked as extensions, discoveries or
other additions and revisions due to the application of reliable technology. Technologies included statistical analysis of
production performance, decline curve analysis, pressure and rate transient 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.
Transfers from proved undeveloped to proved developed reserves included 47 mmboe in the Eagle Ford, 14 mmboe in the
Bakken and 5 mmboe in the Oklahoma Resource Basins due to development drilling and completions.
Costs incurred in 2015, 2014 and 2013 relating to the development of proved undeveloped reserves were $1,415 million,
$3,149 million and $2,536 million.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development
projects which take more than five years to complete, or the timing of when additional gas compression is needed. Of the 603
mmboe of proved undeveloped reserves at December 31, 2015, 26% of the volume is associated with projects that have been
included in proved reserves for more than five years. The majority of this volume is related to a compression project in E.G.
that was sanctioned by our Board of Directors in 2004. During 2012, the compression project received the approval of the E.G.
government, fabrication of the new platform began in 2013 and installation of the platform at the Alba Field occurred in
January 2016. Commissioning is currently underway, with first production expected by mid-2016.
Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the
first time in 2010. This development is being executed by the operator and encompasses a multi-year drilling program including
the design, fabrication and installation of extensive liquid handling and gas recycling facilities. Anecdotal evidence from
similar development projects in the region leads to an expected project execution time frame of more than five years from the
time the reserves were initially booked. Interruptions associated with the civil and political unrest have also extended the
project duration. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and
although temporarily re-opened during the second half of 2014, production remains shut-in through early 2016. The operator is
committed to the project’s completion and continues to assign resources in order to execute the project.
Our conversion rate for proved undeveloped reserves to proved developed reserves for 2015 was 11%. However,
excluding the aforementioned long-term projects in E.G. and Libya, our 2015 conversion rate would be 15%. Furthermore, our
18
5-year annual conversion rate (2011-2015) averaged 21% and would be 32%, excluding the long-term projects in E.G. and
Libya.
All proved undeveloped reserve drilling locations are scheduled to be drilled prior to the end of 2020. As of December 31,
2015, future development costs estimated to be required for the development of proved undeveloped crude oil and condensate,
NGLs, natural gas and synthetic crude oil reserves for the years 2016 through 2020 are projected to be $630 million, $859
million, $1,389 million, $1,764 million and $986 million.
Net Production Sold
Year Ended December 31,
2015
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Total production sold (mboed)
2014
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Total production sold (mboed)
2013
Crude and condensate (mbbld)(a)
Natural gas liquids (mbbld)
Natural gas (mmcfd)(b)
Synthetic crude oil (mbbld)(c)
Total production sold (mboed)
North America
Africa
U.S. Canada
Total
E.G.
Other
Total
Other
Int'l
Disc
Ops
Total
171
39
351
—
269
157
29
310
—
238
126
23
312
—
201
—
—
—
45
45
—
—
—
41
41
—
—
—
42
42
171
39
351
45
314
157
29
310
41
279
126
23
312
42
243
19
10
410
—
97
21
10
439
—
104
23
11
442
—
107
—
—
—
—
—
7
—
1
—
7
24
—
22
—
27
19
10
410
—
97
28
10
440
—
111
47
11
464
—
134
14
—
21
—
18
11
—
21
—
15
14
1
25
—
20
—
—
—
—
—
48
—
37
—
54
81
—
51
—
89
204
49
782
45
429
244
39
808
41
459
268
35
852
42
486
(a)
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid
hydrocarbons.
Excludes volumes acquired from third parties for injection and subsequent resale.
(b)
(c) Upgraded bitumen excluding blendstocks.
Average Sales Price per Unit
(Dollars per unit)
2015
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
2014
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
2013
Crude and condensate (bbl)
Natural gas liquids (bbl)
Natural gas (mcf)
Synthetic crude oil (bbl)
(a)
North America
Africa
U.S. Canada
Total
E.G.
Other
Total
Other
Int'l
Disc
Ops
Total
$ 43.50
13.37
2.66
$ — $ 43.50
— 13.37
2.66
—
40.13
— 40.13
$ 85.25
33.42
4.57
$ — $ 85.25
— 33.42
4.57
—
83.35
— 83.35
$ 94.19
35.12
3.84
$ — $ 94.19
— 35.12
3.84
—
87.51
— 87.51
$ 42.83
1.00
0.24
—
$ 81.01
1.00
0.24
—
$ 90.62
1.00
0.24
—
(a)
(a)
(a)
(a)
(a)
(a)
$ — $ 42.83
1.00
0.24
—
—
—
—
$ 94.70
—
3.11
—
$122.92
—
5.44
—
$ 84.48
1.00
0.25
—
$107.31
1.00
0.49
—
$ 53.91
32.53
6.85
—
$ 94.31
67.73
8.27
—
$110.76
72.14
10.64
—
$ — $ 44.14
— 11.16
1.50
—
— 40.13
$109.80
$ 90.37
— 25.25
2.55
— 83.35
9.94
$112.36
$102.81
— 24.78
2.75
— 87.51
13.01
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.
19
Average Production Cost per Unit(a)
North America
Africa
Disc
Ops
Other
Int'l
$ 27.23
47.06
38.87
(Dollars per boe)
2015
2014
2013
(a)
Total
$ — $ 12.62
15.37
14.51
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.
U.S. Canada
$ 38.42
$ 10.65
46.63
13.34
55.42
13.60
Total
$ 3.23
5.72
3.80
Total
$ 14.69
18.73
20.79
$ 2.37
4.03
2.88
N.M.
N.M.
7.40
E.G. Other
8.92
8.24
N.M. Not meaningful information due to limited sales.
Marketing and Midstream
Our reportable operating segments include activities related to the marketing and transportation of substantially all of our
liquid hydrocarbon, synthetic crude oil and natural gas production. 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.
As discussed previously, we currently own and operate gathering systems and other midstream assets in some of our
production areas. We continue to evaluate midstream infrastructure investments in connection with our development plans.
Delivery Commitments
We have committed to deliver quantities of crude oil and synthetic crude oil, natural gas liquids and natural gas to
customers under a variety of contracts. As of December 31, 2015, those contracts for fixed and determinable quantities were at
variable, market-based pricing and related primarily to liquid hydrocarbon production in the Eagle Ford and Bakken, and OSM
synthetic crude oil production. Eagle Ford liquid hydrocarbon production sales commitments range from a minimum of 128
mbbld in 2016, decreasing to 51 mbbld through 2020. Bakken liquid hydrocarbon production sales commitments range from
10 mbbld to 30 mbbld from 2016 through 2026. Synthetic crude oil production sales commitments are 14 mbbld in 2016 and
10 mbbld in 2017. Eagle Ford natural gas production sales commitments range from a minimum of 210 mmbtu in 2016,
decreasing to 46 mmbtu through 2022.
Our current production rates, forecasts and proved reserves are sufficient to meet these commitments. All of these
contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is
inadequate. Certain volumetric requirements can also be met through purchases of third-party volumes.
In addition to the sales contracts discussed above, we have entered into numerous agreements for transportation and
processing of our equity production. Some of these contracts have volumetric requirements which could require monetary
shortfall penalties if our production is inadequate to meet the terms.
Competition and Market Conditions
Competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of
new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for
the acquisition of oil and natural gas leases and other properties. See Item 1A. Risk Factors for discussion of specific areas in
which we compete and related risks.
We also compete with other producers of synthetic crude oil for the sale of our synthetic crude oil to refineries primarily in
North America. Because not all refineries are able to process or refine synthetic crude oil in significant volumes, sufficient
market demand may not exist at all times to absorb our share of the synthetic crude oil production from the AOSP at
economically viable prices.
Our operating results are affected by price changes for liquid hydrocarbons and natural gas, as well as changes in
competitive conditions in the markets we serve. Generally, results from oil and gas production and OSM operations benefit
from higher liquid hydrocarbons and natural gas prices. Market conditions in the oil and gas industry are cyclical and subject to
global economic and political events and new and changing governmental regulations. See Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations, Overview – Market Conditions for additional discussion of the
impact of prices on our operations.
20
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. Major U.S. federal statutes include, but are not limited to, the Occupational Safety
and Health Act ("OSHA") with respect to the protection of the health and safety of employees, the Clean Air Act ("CAA") with
respect to air emissions, the Federal Water Pollution Control Act (also known as the Clean Water Act ("CWA")) with respect to
water discharges, the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") with respect to
releases and remediation of hazardous substances, the Oil Pollution Act of 1990 ("OPA-90") with respect to oil pollution and
response, the National Environmental Policy Act with respect to evaluation of environmental impacts, the Endangered Species
Act with respect to the protection of endangered or threatened species, the Resource Conservation and Recovery Act ("RCRA")
with respect to solid and hazardous waste treatment, storage and disposal and the U.S. Emergency Planning and Community
Right-to-Know Act with respect to the dissemination of information relating to certain chemical inventories. Other countries in
which we operate have their own laws dealing with similar matters.
These laws and their implementing regulations and other similar state and local laws and rules can impose certain
operational controls for minimization of pollution, 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. 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.
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
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. Although there may be an adverse financial impact (including compliance
costs, potential permitting delays and increased regulatory requirements) associated with this revised regulation, the extent and
magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional
measures and how they will be implemented. 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 September 2015, the EPA published a suite of proposed rules specifically targeting methane emissions from the oil and
gas industry, aggregation of air emissions sources and minor source permitting for operations on tribal lands. These rules are
expected to be finalized in 2016. If we are unable to comply with the final terms of these regulations, we could be required to
forego construction, modification or certain operations. These regulations may also increase compliance costs for some
facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance.
21
In 2010, the EPA promulgated rules that require us to monitor and submit an annual report on our greenhouse gas
emissions. Further, state, national and international requirements to reduce greenhouse emissions are being proposed and in
some cases promulgated (see discussion above regarding proposed regulation of methane emissions from the oil and gas
industry by the EPA). Potential legislation and regulations pertaining to climate change could also affect our operations. The
cost to comply with these laws and regulations cannot be estimated at this time.
In January 2016, the Bureau of Land Management (“BLM”) proposed a rule to further restrict venting and/or flaring of gas
from facilities subject to BLM jurisdiction, and to modify certain royalty requirements. If the rule is finalized as proposed, it
could 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 final 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.
For additional information, see Item 1A. Risk Factors. 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.
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. Federal, state and local-level
laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or
implemented. For example, the U.S. Congress has considered legislation that would require additional regulation affecting the
hydraulic fracturing process, and may be expected to do so in future legislative sessions. Further, 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 addition to such legislative
and regulatory proposals, there are also a number of studies and initiatives underway that may lead to additional proposals in
the future, such as the EPA research study on the potential effects that hydraulic fracturing may have on water quality and
public health. In 2015 the BLM issued a rule governing certain hydraulic fracturing practices on lands within their jurisdiction.
While this rule has been stayed nationwide by court ruling, further findings by the court could result in additional changes to
this new rule.
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.
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. Similar concerns have been raised that hydraulic fracturing may
also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In a few
instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or
suspend operations. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of
the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a
2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater
disposal may vary by region. Some state regulatory agencies have modified their regulations to account for induced seismicity.
Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced
seismicity. In addition, a number of lawsuits have been filed including recent negligence suits and a RCRA citizen suit in
Oklahoma alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and
federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of
injection wells and hydraulic fracturing. Increased regulation and attention given to induced seismicity could lead to greater
opposition, including litigation, to oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal.
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 induced seismicity
22
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.
Transportation
A number of state and federal rules apply to the transportation of liquid hydrocarbons. In 2014, the U.S. Department of
Transportation (“DOT”) finalized a rule relating to testing and classification of liquid hydrocarbons and imposing additional
restrictions on the types of rail cars that may be used in certain types of liquid hydrocarbon service. Although our businesses do
not own rail cars and purchasers of our liquid hydrocarbons make arrangements for its transportation, such regulations could
increase transportation costs which are passed on to Marathon Oil by liquid hydrocarbon purchasers. In addition, the Pipeline
and Hazardous Materials Safety Administration, a sub-agency of DOT, has proposed or announced the intention to propose
various rules related to pipeline transportation of natural gas and/or liquid hydrocarbons. Such regulations could increase the
regulatory burden on our businesses where we own or operate pipelines or could otherwise increase costs to third parties that
are passed on to Marathon Oil.
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 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.
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 2015, sales to Irving Oil and Shell Oil and each of their
respective affiliates accounted for approximately 13% and 11% of our total revenues. In 2014, sales to Shell Oil and its
affiliates accounted for approximately 10% of our total revenues. In 2013, Statoil, the purchaser of the majority of our Libyan
crude oil, accounted for approximately 10% of our total revenues.
Trademarks, Patents and Licenses
We currently hold a number of U.S. and foreign patents and have various pending patent applications. 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 2,611 active, full-time employees as of December 31, 2015. We consider labor relations with our employees to be
satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
Executive Officers of the Registrant
The executive officers of Marathon Oil and their ages as of February 1, 2016, are as follows:
Lee M. Tillman
John R. Sult
Sylvia J. Kerrigan
Catherine L. Krajicek
T. Mitch Little
Lance W. Robertson
Patrick J. Wagner
Gary E. Wilson
54
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50
54
52
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President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Executive Vice President, General Counsel and Secretary
Vice President—Technology and Innovation
Vice President—Conventional
Vice President—Resource Plays
Vice President, Corporate Development
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.
23
Mr. Sult was appointed executive vice president and chief financial officer in September 2013. Prior to joining Marathon
Oil, Mr. Sult served as executive vice president and chief financial officer of El Paso Corporation (a natural gas provider) from
2010 through 2012, senior vice president and chief financial officer from 2009 to 2010, and senior vice president, chief
accounting officer and controller from 2005 to 2009.
Ms. Kerrigan was appointed executive vice president, general counsel and secretary in October 2012, having served as vice
president, general counsel and secretary since November 2009. Prior to these appointments, Ms. Kerrigan served as assistant
general counsel since January 2003.
Ms. Krajicek was appointed vice president—technology and innovation in December 2015, having served as vice
president, health, environment, safety and security since January 2015. Prior to that, Ms. Krajicek held a number of positions of
increasing responsibility with Marathon Oil. Prior to joining the Company in 2007, 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. Little was appointed vice president—conventional in December 2015, having served as 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 for 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. Robertson was appointed vice president—resource plays in December 2015, having served as vice president, North
America production operations since September 2013 and as vice president, Eagle Ford production operations since October
2012. Mr. Robertson joined Marathon Oil in October 2011 as regional vice president, South Texas/Eagle Ford. Between 2004
and 2011, Mr. Robertson held a number of senior engineering and operations management roles of increasing responsibility
with Pioneer Natural Resources Company (an independent oil and gas company) in the U.S. and Canada.
Mr. Wagner was appointed vice president—corporate development in April 2014. Prior to joining Marathon Oil, 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 (a private equity firm), which he joined in early 2012 as vice president, exploitation. Prior to that,
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, Wagner was vice president, Gulf of Mexico, for Devon Energy
Corp. (an oil and natural gas producer), having joined Devon in 2003 as manager, international exploitation.
Mr. 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
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.
24
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.
The recent substantial decline in liquid hydrocarbon and natural gas prices has reduced our operating results and cash
flows and, if continued, could adversely impact our future rate of growth and the carrying value of our assets.
Prices for crude oil and condensate, NGLs, natural gas and synthetic crude oil 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, natural
gas and synthetic crude oil. Historically, the markets for crude oil and condensate, NGLs, natural gas and synthetic crude oil
have been volatile and may continue to be volatile in the future. Beginning in the second half of 2014 and continuing into
2016, prices for WTI and Brent crude oil, Henry Hub natural gas and natural gas liquids have substantially declined.
Furthermore, crude oil and natural gas futures prices indicate that these lower prices may persist for the foreseeable future.
Many of the factors influencing prices of crude oil and condensate, NGLs, natural gas and synthetic crude oil are beyond our
control. These factors include:
• worldwide and domestic supplies of and demand for crude oil and condensate, NGLs, natural gas and synthetic crude oil;
•
•
•
•
•
•
•
•
•
•
•
•
the cost of exploring for, developing and producing crude oil and condensate, NGLs, natural gas and synthetic crude oil;
the ability of the members of OPEC to agree to and maintain production controls;
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, natural gas and synthetic
crude oil are uncertain. The recent substantial declines in commodity prices already have adversely affected our business by:
•
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•
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•
reducing the amount of crude oil and condensate, NGLs, natural gas and synthetic crude oil 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,
natural gas and synthetic crude oil; and
•
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
A further prolonged extension of prices at these levels could extend or exacerbate these adverse effects.
25
A substantial, extended decline in liquid hydrocarbon or natural gas prices 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, oil
sands mining or liquid hydrocarbon or natural gas transportation, 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 remain at
or fall below current levels, 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.
Our offshore operations involve special risks that could negatively impact us.
Offshore exploration and development 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.
Estimates of crude oil and condensate, NGLs, natural gas and synthetic crude oil 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 liquid hydrocarbon and natural gas reserves were prepared by our in-house teams of
reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group. The
synthetic crude oil reserves estimates 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, 2015, 2014 and 2013, as well as other
conditions in existence at those dates. The table below provides the 2015 SEC pricing for certain benchmark prices as well as
the unweighted average for the first two months of 2016:
WTI Crude oil
Henry Hub natural gas
Brent crude oil
Natural gas liquids
$
$
$
$
SEC Pricing 2015
2-month Average 2016
34.19
50.28 $
2.59 $
54.25 $
17.32 $
2.28
34.86
12.87
Any significant future price change could have a material effect on the quantity and present value of our proved reserves.
To the extent that commodity prices remain at current or lower levels throughout 2016, a portion of our proved reserves could
be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as
well as proved undeveloped reserves. If prices remain at the 2-month average depicted above throughout 2016, a material
volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource
category. Assuming lower SEC pricing in 2016, our OSM proved reserves represent the largest risk to be reclassified to non-
proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost
reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices
improve. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation,
among other things.
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Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground
accumulations of crude oil and condensate, NGLs, natural gas and bitumen that cannot be directly measured. (Bitumen is
mined and then upgraded into synthetic crude oil.) Estimates of economically producible reserves and of future net cash flows
depend on a number of variable factors and assumptions, including:
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location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
historical production from the area, compared with production from other comparable producing areas;
volumes of bitumen in-place and various factors affecting the recoverability of bitumen and its conversion into synthetic
crude oil such as historical upgrader performance;
the assumed effects of regulation by governmental agencies;
assumptions concerning future operating costs, severance and excise taxes, development costs and workover and repair
costs; and
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industry economic conditions, levels of cash flows from operations and other operating considerations.
As a result, different petroleum engineers, 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 amounts
or other factors estimated:
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the amount and timing of production;
the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
The discounted future cash flows from our proved crude oil and condensate, NGLs, natural gas and synthetic crude oil
reserves reflected in this Annual Report on Form 10-K should not be considered as the market value of the reserves attributable
to our properties. As required by SEC Rule 4-10 of Regulation S-X, the estimated discounted future cash flows from our
proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves are based on an unweighted average of
closing prices for the first day of each month in the 12-month periods ended December 31, 2015, 2014 and 2013, and costs
applicable at the date of the estimate, while actual future prices and costs may be materially higher or lower.
In addition, the 10% discount factor required by the applicable rules of the SEC to be used to calculate discounted future
cash flows for reporting purposes 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.
If we are unsuccessful in acquiring or finding additional reserves, our future liquid hydrocarbon 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 liquid hydrocarbon 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, natural gas and synthetic crude oil are produced. Accordingly, to the extent we are not successful in replacing the crude
oil and condensate, NGLs, natural gas and synthetic crude oil we produce, our future revenues will decline. Creating and
maintaining an inventory of prospects for future production depends on many factors, including:
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obtaining rights to explore for, develop and produce crude oil and condensate, NGLs, natural gas and synthetic crude oil
in promising areas;
drilling success;
the ability to complete long lead-time, capital-intensive projects timely and cost effectively;
the ability to find or acquire additional proved reserves at acceptable costs; and
the ability to fund such activity.
27
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 liquid hydrocarbon and natural gas reservoirs. The costs of drilling, completing and
operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of
factors, including:
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unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
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 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 engineering, procurement and construction of
facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted
internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us
to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise
as a result of unpredictable factors, many of which are beyond our control, including:
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denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
increased costs or operational delays resulting from shortages of water;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills)
affecting our facilities, or those of vendors or suppliers;
•
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
• market-related increases in a project’s debt or equity financing costs; and
•
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.
We may incur substantial capital expenditures and operating costs as a result of compliance with, and/or 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.
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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., Canada, 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 proposed regulations targeting methane emissions from the oil
and gas industry, which are expected to be finalized in 2016. 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, natural gas and synthetic crude oil, 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,
including the operation of injection wells, 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 operations. Hydraulic fracturing
has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local-level
laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or
implemented. For example, the U.S. Congress has considered legislation that would require additional regulation affecting the
hydraulic fracturing process, and may be expected to do so in future legislative sessions. Further, 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 addition to such legislative
and regulatory proposals, there are also a number of studies and initiatives underway that may lead to additional proposals in
the future, such as the EPA research study on the potential effects that hydraulic fracturing may have on water quality and
public health. In 2015 the Bureau of Land Management issued a rule governing certain hydraulic fracturing practices on lands
within their jurisdiction. While this rule has been stayed nationwide by court ruling, further findings by the court could result in
additional changes to this new rule.
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.
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. Similar concerns have been raised that hydraulic fracturing may
also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In a few
instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or
suspend operations. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of
the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a
2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater
disposal may vary by region. Some state regulatory agencies have modified their regulations to account for induced seismicity.
Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced
seismicity. In addition, a number of lawsuits have been filed including recent negligence suits and a RCRA citizen suit in
Oklahoma alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and
federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of
injection wells and hydraulic fracturing. Increased regulation and attention given to induced seismicity could lead to greater
opposition, including litigation, to oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal.
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
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fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding induced seismicity
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.
Worldwide political and economic developments and changes in law 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 39% of our
liquid hydrocarbon and natural gas sales volumes related to continuing operations in 2015 was derived from production outside
the U.S. and 56% of our proved crude oil and condensate, NGLs and natural gas reserves as of December 31, 2015 were located
outside the U.S. All of our synthetic crude oil production and proved reserves are located in Canada. 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., Ethiopia,
Gabon, the Kurdistan Region of Iraq and Libya, and in global markets including:
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changes in governmental policies relating to liquid hydrocarbon 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
•
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, including Bahrain, Egypt, Iraq, Libya, Syria, Tunisia and Yemen. 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 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, natural gas and synthetic
crude oil. 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.
Actions of governments through tax legislation 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.
Our total debt was $7.3 billion as of December 31, 2015. 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;
30
•
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;
• we may be at a competitive disadvantage as compared to similar companies that have less debt; and
•
additional financing in the future for working capital, capital expenditures, acquisitions or development activities,
general corporate or other purposes may have higher costs and more restrictive covenants.
We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for
general corporate or other purposes. A higher level of indebtedness increases the risk that our financial flexibility may
deteriorate. Our ability to meet our debt obligations and service our debt depends on future performance. General economic
conditions, crude oil and condensate, NGLs, natural gas and synthetic crude oil 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 17 to the
consolidated financial statements for a discussion of debt obligations.
A downgrade in our credit rating, particularly below investment grade, 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. The credit rating process is contingent
upon a number of factors, many of which are beyond our control. A downgrade of our credit ratings, particularly below
investment grade, 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 restrict our access to the commercial paper market. We could also be
required to post letters of credit or other forms of collateral for certain 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.
Our commodity price risk management may prevent us from fully benefiting from commodity price increases and may
expose us to other risks, including counterparty risk.
To the extent that we engage in price risk management activities to protect ourselves against commodity price declines, we
may be prevented from fully realizing the benefits of price increases above the 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 cyber-attacks targeting our computer and telecommunications systems
and infrastructure.
Our business, like other companies in the oil and gas industry, has become increasingly dependent on digital technologies.
Such technologies are integrated into our business operations and used as a part of our liquid hydrocarbon and natural gas
production and distribution systems in the U.S. and abroad, including those systems used to transport production to market.
Use of the internet and other public networks for communications, services, and storage, including “cloud” computing, exposes
users (including our business) to cybersecurity risks. While our information systems and related infrastructure experienced
attempted and actual minor breaches of our cybersecurity in the past, 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 cyber-attacks continue to evolve, we may be required to expend significant
additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information
systems and related infrastructure security vulnerabilities.
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, natural gas and synthetic crude oil,
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.
31
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 liquid hydrocarbon and natural gas properties. 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 liquid hydrocarbon
and natural gas reserves (as previously discussed), actual future production rates and associated costs with respect to acquired
properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition,
an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods
in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to
effectively integrate the acquired properties into our ongoing operations.
We 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 liquid hydrocarbon 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, or
oil sands mining, 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 North America E&P and International E&P operations are subject to unplanned occurrences, including blowouts,
explosions, fires, loss of well control, spills, hurricanes and other adverse weather, tsunamis, earthquakes, volcanic eruptions or
nuclear or other disasters, labor disputes and accidents. Our OSM operations are subject to business interruptions due to
breakdown or failure of equipment or processes and unplanned events such as fires, earthquakes, explosions or other
interruptions. 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 and 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 certain of
our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable
32
or available only for reduced amounts of coverage. For example, due to hurricane activity in recent years, the availability of
insurance coverage for windstorms has been reduced or, in many instances, it is prohibitively expensive. As a result, our
exposure to losses from future windstorm activity has increased.
Litigation by private plaintiffs or government officials 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, antitrust 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.
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.
33
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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The location and general character of our principal liquid hydrocarbon and natural gas properties, oil sands mining
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, natural gas and synthetic crude oil 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 defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty
claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with
certainty, we believe that the resolution of these proceedings will not have a material adverse effect on our consolidated
financial position, results of operations or cash flows.
Environmental Proceedings
The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2015
under federal and state environmental laws. Except as described herein, it is not possible to predict accurately the ultimate
outcome of these matters; however, management’s belief set forth in the first paragraph under Legal Proceedings above takes
such matters into account.
As of December 31, 2015, 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, which is in many cases preliminary and incomplete, we have approximately $4 million accrued
to address the clean-up and remediation costs connected with these sites.
The projected liability for clean-up and remediation provided in the preceding paragraph is a forward-looking statement.
To the extent that our assumptions prove to be inaccurate, future expenditures may differ materially from those stated in the
forward-looking statement.
Item 4. Mine Safety Disclosures
Not applicable.
34
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, 2016, there were 37,608 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
$29.63
$31.19
$25.79
$20.18
$31.19
2015
Low Price
$25.47
$25.92
$14.04
$12.38
$12.38
Dividends
$0.21
$0.21
$0.21
$0.05
$0.68
High Price
$35.52
$40.16
$41.69
$37.13
$41.69
2014
Low Price
$31.81
$34.90
$37.59
$24.80
$24.80
Dividends
$0.19
$0.19
$0.21
$0.21
$0.80
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, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities
Exchange Act of 1934:
Column (a)
Column (b)
Column (c)
Period
10/01/15 – 10/31/15
11/01/15 – 11/30/15
12/01/15 – 12/31/15
Total
Total Number of
Shares
Purchased(a)
Average
Price Paid
per Share
46,156
4,179
1,049 (b)
51,384
$18.44
$18.19
$19.18
$18.44
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs(c)
Column (d)
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs(c)
1,500,285,529
1,500,285,529
1,500,285,529
— $
— $
— $
—
51,384 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(a)
(b) Does not include shares repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil
Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend
Reinvestment Plan. On March 9, 2015, the Dividend Reinvestment Plan was terminated. Participants in the Dividend Reinvestment Plan were transferred
to Computershare CIP, a Direct Stock Purchase and Dividend Reinvestment Plan, which is sponsored and administered by Computershare Trust Company,
N.A.
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, 2015 is $1.5 billion. No repurchases were
made under the program in 2015.
(c)
35
Item 6. Selected Financial Data
(In millions, except per share data)
Statement of Income Data(a)(b)
Revenues
Income (loss) from continuing operations
Net income (loss)
Per Share Data(a)(b)
Basic:
Income (loss) from continuing operations
Net income (loss)
Diluted:
Income (loss) from continuing 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(c)
Total assets
Total long-term debt, including capitalized leases
(a)
2015
Year Ended December 31,
2013
2012
2014
$
$
$
$
$
$
$
5,522
(2,204)
(2,204)
10,846
969
3,046
(3.26) $
(3.26) $
(3.26) $
(3.26) $
1.42
4.48
1.42
4.46
$
3,476
460
$0.68
5,160
543
$0.80
$
$
$
$
$
$
$
$
$
$
$
$
11,325
931
1,753
1.32
2.49
1.31
2.47
4,443
508
$0.72
$
$
$
$
$
$
11,966
856
1,582
1.21
2.24
1.21
2.23
4,361
480
$0.68
2011
11,088
467
2,946
0.66
4.15
0.65
4.13
2,767
567
$0.80
31,344
4,647
Includes impairments to producing properties of $412 million, $132 million, $96 million, $371 million and $310 million in 2015, 2014, 2013, 2012 and
2011 and impairments to unproved properties of $964 million, $306 million, $572 million and $227 million in 2015, 2014, 2013 and 2012 (see Item 8.
Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements)). Includes a goodwill impairment of $340 million in
2015 related to the N.A. E&P reporting unit. (see Item 8. Financial Statements and Supplementary Data – Note 14 to the consolidated financial
statements).
35,269
6,475
35,588
6,362
35,983
5,295
32,311
7,276
$
$
$
$
$
(b) We closed the sale of our Angola assets and our Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note 5 to the
consolidated financial statements); and our downstream business was spun-off in 2011. The applicable periods have been recast to reflect these
businesses as discontinued operations.
Prior year periods were adjusted to reflect debt issuance costs as a direct reduction from the associated debt liability in our consolidated balance sheets
with the adoption of the debt issuance costs standard in the fourth quarter of 2015. See Note 2 for information.
(c)
36
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:
• North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North
America;
•
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of
North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in
E.G.; and
• Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades
the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Executive Summary
We were able to increase net sales volumes by 20% in the three core U.S. resource plays despite a significant reduction in
capital expenditures caused by the deterioration in commodity prices during 2015. Our focus on cost discipline and efficiencies
yielded sustainable savings in both operating expenses and capital costs. We prioritized capital allocation to our domestic
unconventional resource plays and scaled back our conventional exploration program. We continued to progress our program of
non-core asset sales and realized aggregate net proceeds of $225 million. We ended 2015 with liquidity of $4.2 billion
comprised of $1.2 billion of cash and $3.0 billion available through a committed multi-year credit facility. Despite current
commodity prices, we believe that we can satisfy operational objectives and capital commitments with the cash and cash
equivalents on hand, internally generated cash flow from operations, available borrowing capacity, the flexibility to adjust our
Capital Program and our non-core asset disposition program. Our target for non-core asset dispositions is now $750 million to
$1 billion, an increase from our previous goal of $500 million.
Significant 2015 operating and financial activities include the following:
•
Increased company-wide net sales volumes from continuing operations by 6% to 438 mboed from 415 mboed
Net sales volumes from our three U.S. resource plays increased 20% to 218 mboed from 181 mboed
• Maintained focus on cost discipline and efficiencies
Reduced our 2015 Capital Program by approximately 50% from the prior year, down to $3 billion, reflecting
continued capital discipline and benefits from operating efficiencies
Reduced company-wide production expenses per boe in 2015
North America E&P - 28% reduction to $7.38 per boe
International E&P - 28% reduction to $5.99 per boe
Rationalized the workforce during 2015, and expect to generate a future annualized net savings of $160
million from a 20% reduction in workforce
• Active management of liquidity and capital structure
At December 31, 2015:
Liquidity of $4.2 billion
Cash-adjusted debt-to-capital ratio was 25%
Issued $2 billion aggregate principal amount of unsecured senior notes, $1 billion of which was used to repay
the 0.90% senior notes that matured in November 2015
Increased the capacity of the revolving credit facility to $3.0 billion while also extending the maturity date to
May 2020
Repatriated Canadian earnings in a tax efficient manner, providing $250 million of cash available for use in
U.S. operations
Reduced the quarterly dividend beginning in the third quarter, from $0.21 per share to $0.05 per share
•
Portfolio management activities
We continue to make progress in our non-core asset divestitures, with a goal of $750 million to $1 billion
Closed on the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in
August 2015 for net proceeds of approximately $100 million
Closed on the sale of certain Gulf of Mexico properties in December 2015 for net cash proceeds of $111
million
37
Signed an agreement for the sale of our East Africa exploration acreage in Kenya and Ethiopia; the
Kenya transaction closed in February 2016 and Ethiopia is expected to close during the first quarter of
2016.
•
Financial results
Loss from continuing operations per diluted share of $3.26 in 2015 as compared to income from continuing
operations of $1.42 per diluted share in 2014, reflecting the impact of lower commodity prices
Included in the loss for 2015 are $1.4 billion ($1.7 billion pre-tax) of charges comprised largely of losses and
asset impairments resulting from lower forecasted commodity prices, goodwill impairment and changes in
our conventional exploration strategy (refer to North America E&P - Exploration and International E&P -
Exploration in Item 1. Business)
Recorded non-cash deferred tax expense of $135 million in 2015 related to the increase in Alberta's provincial
corporate income tax rate
Operating cash flow provided by continuing operations for 2015 was $1.6 billion, compared to $4.7 billion in
2014, reflecting the lower commodity price environment
38
Outlook
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the
amount of capital available to reinvest into our business. Commodity prices began declining in the second half of 2014 and
continued through 2015 and into 2016. We believe we can manage in this lower commodity price cycle through operational
execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, while continuing to focus on
balance sheet protection.
Capital Program
Our Board of Directors approved a Capital Program of $1.4 billion for 2016. We intend to be flexible with respect to our
capital allocation decisions in light of this challenged commodity pricing environment. With that in mind, we have engaged in
an active program to divest of non-core assets, which together with our anticipated cash flows from operations, plus the savings
embedded from the cost reductions we have put in place, should allow us to meet our current Capital Program, operating costs,
debt service and dividends. The discipline undertaken as part of a real-time evaluation of our revenues, expenditures, and asset
dispositions should allow us to live within our means.
Our Capital Program is broken down by reportable segment in the table below:
(In millions)
North America E&P
International E&P
Oil Sands Mining
Segment total
Corporate and other
Total Capital Program
2016 Capital
Program
Percent of
Total
$
$
1,166
185
41
1,392
40
1,432
81%
13%
3%
97%
3%
100%
North America E&P – Approximately $1.2 billion of our Capital Program is allocated to our three core U.S. resource plays.
Eagle Ford - Approximately $600 million is planned, we expect to average five rigs and bring 124-132 gross-operated
wells to sales. Included in Eagle Ford spending is approximately $520 million for drilling and completions. The 2016 drilling
program will continue to focus on the co-development of the Lower and Upper Eagle Ford horizons as well as Austin Chalk in
the core of the play.
Oklahoma Resource Basins - Spending of approximately $200 million is targeted, we expect to average two rigs which will
focus primarily on lease retention in the STACK and delineation of the Meramec, and bring 20-22 gross-operated wells to sales.
Spending includes approximately $195 million for drilling and completions, including $55 million for outside-operated activity.
We expect to be approximately 70% held by production in the STACK by year end, with SCOOP already 90% held by
production.
Bakken - We plan to spend just under $200 million in North Dakota. Drilling activity will average one rig for half of 2016
and bring online 13-15 gross-operated wells. Bakken spending includes approximately $150 million for drilling and
completions, including $75 million for outside-operated activity. Facilities and infrastructure spending will be significantly
lower than 2015 with the next phase of the water-gathering system scheduled to be complete in the second half of 2016.
International E&P – Approximately $170 million of our Capital Program is dedicated to our international assets, primarily
in E.G. and the Kurdistan Region of Iraq. The Alba field compression project in E.G. remains on schedule to start up by mid-
year, and will extend plateau production by two years as well as the asset’s life by up to eight years.
Approximately $30 million of our Capital Program will be spent on a targeted exploration program impacting both the
North America E&P and the International E&P segments. Activity in 2016 is limited to fulfilling existing commitments in the
Gulf of Mexico and Gabon, with no operated exploration wells planned.
Oil Sands Mining – We expect to spend $40 million of the Capital Program for sustaining capital projects.
The remainder of our Capital Program consists of Corporate and Other and is expected to total approximately $40 million.
For information about expected exploration and development activities more specific to individual assets, see Item 1.
Business.
Production Volumes
We forecast 2016 production available for sale from the combined North America E&P and International E&P segments,
excluding Libya, to average 335 to 355 net mboed and the OSM segment to average 40 to 50 net mbbld of synthetic crude oil.
39
Acquisitions and Dispositions
Excluded from our Capital Program are the impacts of acquisitions and dispositions not previously announced. We
continually evaluate ways to optimize our portfolio through acquisitions and divestitures. In connection with our ongoing
portfolio management, future decisions to dispose of assets could result in non-cash impairments in the period such decisions
are made.
Operations
Our net sales volumes from continuing operations averaged 438 mboed, 415 mboed and 404 mboed for 2015, 2014 and
2013. As liftings from Libya were sporadic during this 3-year period, a more representative comparison is net sales volumes
from continuing operations excluding Libya, which was 438 mboed, 408 mboed and 376 mboed for 2015, 2014 and 2013. The
continued ramp up of production from our U.S. resource plays has been the most significant contributor to the increases when
comparing results excluding Libya, partially offset by decreases from domestic asset sales and normal production declines.
Net Sales Volumes
North America E&P (mboed)
International E&P (mboed)
Oil Sands Mining (mbbld) (a)
Total Continuing Operations (mboed)
(a)
Includes blendstocks.
North America E&P
2015
269
116
53
438
Increase
(Decrease)
13 %
(9)%
6 %
6 %
2014
238
127
50
415
Increase
(Decrease)
18 %
(18)%
4 %
3 %
2013
201
155
48
404
The following tables provide additional detail regarding net sales volumes, sales mix and operational drilling activity:
Net Sales Volumes
Eagle Ford
Oklahoma Resource Basins
Bakken
Other North America(a)
Total North America E&P (mboed)
Includes Gulf of Mexico and other conventional onshore U.S. production, plus Alaska in 2013.
(a)
2015
134
25
59
51
269
Increase
(Decrease)
20%
39%
16%
(11)%
13%
2014
112
18
51
57
238
Increase
(Decrease)
38%
29%
31%
(15)%
18%
2013
81
14
39
67
201
Sales Mix - U.S. Resource Plays - 2015
Crude oil and condensate
Natural gas liquids
Natural gas
Drilling Activity - U.S. Resource Plays
Gross Operated
Eagle Ford:
Wells drilled to total depth
Wells brought to sales
Oklahoma Resource Basins:
Wells drilled to total depth
Wells brought to sales
Bakken:
Wells drilled to total depth
Wells brought to sales
Eagle Ford
60%
19%
21%
Oklahoma
Resource
Basins
19%
28%
53%
Bakken
87%
7%
6%
2015
2014
2013
251
276
21
20
35
56
360
310
19
18
83
69
299
307
10
9
76
77
40
North America E&P segment average net sales volumes in 2015 increased 13% when compared to 2014. Net liquid
hydrocarbon sales volumes increased 24 mbbld and net natural gas sales volumes increased 41 mmcfd in 2015 primarily
reflecting continued growth from our three core U.S. resource plays.
North America E&P segment average net sales volumes in 2014 increased 18% when compared to 2013, primarily due to
higher liquid hydrocarbon net sales volumes resulting from ongoing development programs in our three key U.S. resource
plays. This was partially offset by lower natural gas sales volumes, primarily due to the shut-in and exit from Powder River
Basin operations.
Refer to the Item 1. Business section for additional detail related to net sales volumes by asset.
International E&P
The following table provides net sales volumes from continuing operations:
Net Sales Volumes
Equivalent Barrels (mboed)
Equatorial Guinea
United Kingdom(a)
Libya
Total International E&P (mboed)
Net Sales Volumes of Equity Method Investees
2015
Increase
(Decrease)
2014
Increase
(Decrease)
2013
97
19
—
116
(7)%
19 %
(100)%
(9)%
104
16
7
127
(3)%
(20)%
(75)%
(18)%
— %
(13)%
107
20
28
155
6,548
1,249
LNG (mtd)
Methanol (mtd)
Includes natural gas acquired for injection and subsequent resale of 8 mmcfd, 6 mmcfd and 7 mmcfd for 2015, 2014, and 2013.
(10)%
(14)%
6,535
1,092
5,884
937
(a)
International E&P segment average net sales volumes in 2015 decreased 9% when compared to 2014. We did not record
any sales from Libya in 2015 as a result of the shutdown of the Es Sider crude oil terminal and ongoing civil unrest. Sales
volumes in Equatorial Guinea were lower due to a series of turnarounds and other maintenance activities performed at the Alba
field, EG LNG and AMPCO facilities during the year. In the U.K., sales volumes increased as we completed the five-well Brae
infill drilling program that began in 2014. The Brae Alpha installation experienced a process pipe failure in December 2015.
Repairs are underway and full production is expected to resume in the second quarter of 2016.
International E&P segment average net sales volumes in 2014 decreased 18% when compared to 2013. We had lower sales
from Libya in 2014 as a result of the shutdown of the Es Sider crude oil terminal which was temporarily re-opened during the
second half of 2014. Excluding Libya, net sales volumes decreased 6%, primarily due to reliability issues and production
decline in the U.K. and lower reliability at the non-operated methanol facility in E.G.
Refer to the Item 1. Business section for additional detail related to net sales volumes by asset.
Oil Sands Mining
Our OSM operations consist of a 20% non-operated working interest in the AOSP. Our net synthetic crude oil sales
volumes were 53 mbbld in 2015 compared to 50 mbbld in 2014 and 48 mbbld in 2013.
41
Market Conditions
Oil and gas price declines during 2015 and into 2016 are reflective of robust supply growth from both OPEC and non-
OPEC production around the world. The effect of this supply growth on prices was exacerbated by weakening demand growth
in emerging markets and OPEC's formal abandonment of production targets in December 2015. Crude oil, natural gas and
NGLs benchmark prices are likely to remain volatile based on global supply and demand and declined further subsequent to
December 31, 2015 as compared to the average realized prices in the tables below. See Item 1A. Risk Factors and Item 7.
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Estimates for
further discussion of how a further decline in commodity prices could impact us.
North America E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas
for 2015, 2014 and 2013:
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)
Benchmarks
WTI crude oil average of daily prices (per bbl)
LLS crude oil average of daily prices (per bbl)
Mont Belvieu NGLs (per bbl) (c)
Henry Hub natural gas settlement date average (per mmbtu)
2015
Decrease
2014
Decrease
2013
$43.50
13.37
37.85
2.66
$48.76
52.33
16.94
2.66
(49)% $85.25
33.42
(60)%
77.02
(51)%
4.57
(42)%
(48)% $92.91
96.64
(46)%
32.52
(48)%
4.42
(40)%
(9)%
(5)%
(10)%
19 %
(5)%
(10)%
(4)%
21 %
94.19
35.12
85.20
3.84
98.05
107.36
33.78
3.65
(a)
(b)
(c)
Excludes gains or losses on derivative instruments.
Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations per
barrel by $1.24 and $(0.27) for 2015 and 2013. There were no crude oil derivative instruments for 2014.
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 2015, 2014 and
2013:
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)
(a) Average of monthly prices obtained from EIA website.
2015
Decrease
2014
Decrease
2013
$47.50
2.81
36.67
0.68
(46)%
14 %
(47)%
(6)%
$87.23
2.46
68.98
0.72
(19)% $108.18
5.24
(53)%
91.04
(24)%
1.15
(37)%
$52.35
(47)%
$99.02
(9)% $108.64
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. The Alba Plant extracts NGLs and secondary
condensate from gas, leaving dry natural gas. The processed NGLs are sold by Alba Plant at market prices, with our share of its
income/loss reflected in Income from equity method investments. 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 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
42
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.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by
operational reliability or planned unit outages at the mines or upgrader. Sales prices for synthetic crude oil historically tracked
movements in the WTI crude oil and the WCS Canadian heavy crude oil benchmarks. The influence of each benchmark can
change from period to period based on market dynamics.
The following table presents our average price realizations and the related benchmarks that impacted both our revenues and
variable costs for 2015, 2014 and 2013:
Average Price Realizations
Synthetic Crude Oil (per bbl)
Benchmark
WTI crude oil (per bbl)
WCS crude oil (per bbl)(a)
2015
Increase
(Decrease)
2014
Increase
(Decrease)
2013
$40.13
(52%)
$83.35
(5%)
$87.51
$48.76
35.28
(48%)
(52%)
$92.91
73.60
(5%)
1%
$98.05
72.77
(a) Average of monthly prices based upon average WTI adjusted for differentials unique to western Canada.
Consolidated Results of Operations: 2015 compared to 2014
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
North America E&P
International E&P
Oil Sands Mining
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,
2015
2014
$
$
3,358 $
728
815
4,901
50
4,951 $
5,770
1,410
1,556
8,736
—
8,736
43
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,
2014
Increase (Decrease) Related to
Price Realizations Net Sales Volumes
Year Ended
December 31,
2015
$
North America 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
$
$
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
Other sales
Total
$
$
$
5,240
516
—
14
5,770
1,240
124
46
1,410
1,525
31
1,556
$
$
(3,006) $
(243)
78
671
68
$
$
(509) $
(8)
(153) $
(8)
(842) $
98
$
$
$
2,905
341
78
34
3,358
578
108
42
728
781
34
815
Marketing revenues decreased $1,539 million in 2015 from 2014. 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 the lower commodity price environment
as well as lower marketed volumes in North America.
Income from equity method investments decreased $279 million primarily due to lower price realizations for LPG at our
Alba Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all of which are located in
E.G. Also contributing to the decrease were lower sales volumes due to planned turnaround and maintenance activities at the
AMPCO methanol plant, the Alba field and the LNG facility.
Net gain on disposal of assets in 2015 was related to the sale of our operated producing properties in the greater Ewing
Bank area and non-operated producing interests in the Petronius field in the Gulf of Mexico. The gain associated with those
assets was partially offset by the loss on sale of East Africa exploration acreage in Ethiopia and Kenya. The net loss on disposal
of assets in 2014 was primarily related to the sale of non-core acreage located in the far northwest portion of the Williston
Basin. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for
information about these dispositions.
Production expenses decreased $552 million in 2015 from 2014. Our focus on cost discipline and efficiencies yielded
sustainable savings in production costs. North America E&P declined $167 million due to lower operational, maintenance and
labor costs. International E&P declined $131 million due to lower project work, repair, maintenance and turnaround costs, as
well as lower production volumes. OSM declined $254 million primarily due to cost management, especially staffing and
contract labor, lower fuel and utility costs, and lower feedstock purchases given the increased mine and upgrader reliability,
combined with a more favorable exchange rate on expenses denominated in the Canadian dollar.
The production expense rate (expense rate per boe) decreased for each of our segments as total production costs declined
due to reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume
increases, which further contributed to the expense rate decline. The following table provides production expense rates for each
segment:
44
($ per boe)
North America E&P
International E&P
Oil Sands Mining (a)
2015
2014
$7.38
$5.99
$36.48
$10.25
$8.31
$44.53
(a)
Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and
insurance costs and excludes pre-development costs.
Marketing expenses decreased $1,536 million in 2015 from the prior year, consistent with the decrease in marketing
revenues discussed above.
Exploration expenses increased $525 million in 2015, primarily due to higher unproved property impairments in North
America. During 2015, we made a strategic decision to reduce the overall level of our conventional exploration program; as a
result, we impaired our Canadian in-situ assets, certain of our leases in the Gulf of Mexico and the Harir block in the Kurdistan
Region of Iraq. We also impaired unproved property in Colorado in 2015, which we deemed uneconomic given our forecasted
natural gas prices.
Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or we
decided not to drill or extend.
Dry well costs for 2015 include the operated Solomon well in the Gulf of Mexico, our operated Sodalita West #1
exploratory well in E.G., and suspended well costs related to our Canadian in-situ assets at Birchwood. Dry well costs in 2014
also included our operated Sodalita West #1 exploratory well in E.G. which was drilling over year-end 2014, the operated Key
Largo well, outside-operated Perseus well and the outside operated second Shenandoah appraisal well, all of which are located
in the Gulf of Mexico. In addition, 2014 also includes our exploration programs in the Kurdistan Region of Iraq, Ethiopia and
Kenya.
The following table summarizes the components of exploration expenses:
(In millions)
Unproved property impairments
Dry well costs
Geological and geophysical
Other
Total exploration expenses
Year Ended December 31,
2015
2014
$
$
964 $
250
31
73
1,318 $
306
317
85
85
793
Exploration expense are also discussed in Item 8. Financial Statements and Supplementary Data - Note 13 to the
consolidated financial statements.
Depreciation, depletion and amortization increased $96 million in 2015 from the prior year primarily as a result of higher
North America E&P net sales volumes from our three U.S. resource plays. Our segments apply the units-of-production method
to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes
have an impact on DD&A expense.
The DD&A rate (expense rate per boe), which is impacted by changes in proved reserves, capitalized costs and sales
volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The
DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in the Eagle Ford. The
International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program.
($ per boe)
North America E&P
International E&P
Oil Sands Mining
2015
2014
$24.24
$6.95
$12.48
$26.95
$5.79
$12.07
Impairments for 2015 included $340 million for the goodwill impairment of the North America E&P reporting unit, $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. Impairments for 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a
result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Item 8. Financial Statements
and Supplementary Data - Note 13 and Note 14 to the consolidated financial statement for additional detail.
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase
or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price
45
realizations, taxes other than income decreased $172 million in 2015. This decrease was partially offset by an increase in sales
volumes in North America E&P. The following table summarizes the components of taxes other than income:
(In millions)
Production and severance
Ad valorem
Other
Total
Year Ended December 31,
2015
2014
$
$
131 $
39
64
234 $
240
74
92
406
General and administrative expenses decreased $64 million primarily due to cost savings realized from the workforce
reductions that occurred during 2015. This decrease was partially offset by severance expenses of $55 million associated with
the workforce reductions and an increase in pension settlement expense. Pension settlement expenses in 2015 totaled $119
million as compared to $99 million in 2014.
Net interest and other increased $29 million primarily due to increased interest expense associated with an increase in
long-term debt. The components of net interest and other are detailed in Item 8. Financial Statements and Supplementary Data
- Note 8 to the consolidated financial statements.
Provision (benefit) for income taxes reflects an effective tax rate of (25%) and 29% for each of 2015 and 2014. See Item
8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for a discussion of the
effective income tax rate.
Discontinued operations is presented net of tax. We closed the sale of our Angola assets and Norway business in 2014,
and both are reflected as discontinued operations for 2014. Included in the discontinued operations for 2014 are after-tax gains
of $532 million and $976 million related to the dispositions of Angola and Norway respectively. See Item 8. Financial
Statements and Supplementary Data - Note 5 to the consolidated financial statements.
Segment Results: 2015 compared to 2014
Segment income (loss) for 2015 and 2014 is summarized and reconciled to net income (loss) in the following table.
(In millions)
North America E&P
International E&P
Oil Sands Mining
Segment income (loss)
Items not allocated to segments, net of income taxes
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Year Ended December 31,
2015
2014
$
$
(486) $
112
(113)
(487)
(1,717)
(2,204)
—
(2,204) $
693
568
235
1,496
(527)
969
2,077
3,046
North America E&P segment income (loss) decreased $1,179 million in 2015 compared to 2014. The decrease was
primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from
the three U.S resource plays and lower production costs (even though net sales volumes increased).
International E&P segment income decreased $456 million in 2015 compared to 2014. The decrease was largely due to
lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially
offset by lower production, operating and exploration expenses.
Oil Sands Mining segment income (loss) decreased $348 million in 2015 compared to 2014 primarily as result of lower
price realizations, partially offset by higher sales volumes and reduced production expenses.
46
Consolidated Results of Operations: 2014 compared to 2013
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
North America E&P
International E&P
Oil Sands Mining
Segment sales and other operating revenues, including related party
Unrealized gain (loss) on crude oil derivative instruments
Sales and other operating revenues, including related party
Year Ended December 31,
2014
2013
$
$
5,770 $
1,410
1,556
8,736
—
8,736 $
5,068
2,654
1,576
9,298
(52)
9,246
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 and average price realizations.
Year Ended
December 31,
2013
Increase (Decrease) Related to
Price Realizations Net Sales Volumes
Year Ended
December 31,
2014
$
(In millions)
North America 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
$
$
$
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil
Other sales
Total
$
$
$
4,638
437
(15)
8
5,068
2,398
209
47
2,654
1,542
34
1,576
$
$
(557) $
82
15
(397) $
(74)
$
1,159
(3)
$
(761) $
(11)
(76) $
59
$
$
$
5,240
516
—
14
5,770
1,240
124
46
1,410
1,525
31
1,556
Marketing revenues increased $31 million in 2014 from 2013. 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 increase in 2014 is primarily due to higher marketing activity levels in both the North
America E&P and OSM segments.
Net loss on disposal of assets in 2014 primarily includes the pretax loss on the sale of non-core acreage located in the far
northwest portion of the Williston Basin. The net loss on disposal of assets in 2013 primarily included pretax losses on the sale
of our DJ Basin interests and the conveyance of our Marcellus interests to the operator, partially offset by pretax gains on the
sales of the Neptune gas plant and our remaining assets in Alaska. See Item 8. Financial Statements and Supplementary Data -
Note 5 to the consolidated financial statements for further details about these dispositions.
Production expenses increased $90 million in 2014 from 2013 primarily related to increased North America E&P net sales
volumes in the Eagle Ford and Bakken. The production expense rate (expense per boe) decreased in North America E&P
in 2014 compared to 2013 primarily due to improved operating efficiencies in the Eagle Ford. The expense per boe increased
in the International E&P segment due to a subsea power project at our non-operated Foinaven field as well as a turnaround in
Brae in the U.K. and a non-recurring riser repair in E.G.
47
The following table provides production expense rates for each segment:
($ per boe)
North America E&P
International E&P
Oil Sands Mining (a)
(a) Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and
$10.25
$8.31
$44.53
2014
2013
$10.86
$6.36
$46.30
insurance costs and excludes pre-development costs.
Other operating expenses increased $73 million in 2014 from the prior year, primarily due to increased shipping and
handling costs in North America in line with increased sales volumes, as well as the impact of a settlement related to the
calculation of the net profits interest payments associated with our Alba Plant equity interests in E.G.
Marketing expenses increased $29 million in 2014 from the prior year, consistent with the decreases in marketing revenues
discussed above.
Exploration expenses were $98 million lower in 2014 than in 2013, primarily related to our North America E&P segment
as a result of larger non-cash unproved property impairments during 2013 related to Eagle Ford leases that either expired or that
we did not expect to drill. These decreases were partially offset by increases in 2014 expenses related to the operated Key
Largo, the outside-operated Perseus, the outside-operated second Shenandoah appraisal 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)
Unproved property impairments
Dry well costs
Geological and geophysical
Other
Total exploration expenses
Year Ended December 31,
2014
2013
$
$
306 $
317
85
85
793 $
572
148
80
91
891
Exploration expense are also discussed in Item 8. Financial Statements and Supplementary Data - Note 13 to the
consolidated financial statements.
Depreciation, depletion and amortization increased $361 million in 2014 from the prior year. Our segments apply the
units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve
and production volumes have an impact on DD&A expense. Increased DD&A expense in 2014 is primarily due to higher North
America E&P sales volumes as a result of ongoing development programs over our three U.S. resource plays.
The DD&A rate, which is impacted by changes in reserves, capitalized costs and sales volume mix by field, can also cause
changes to our DD&A. The following table provides DD&A rates for each segment:
($ per boe)
North America E&P
International E&P
Oil Sands Mining
2014
2013
$26.95
$5.79
$12.07
$26.23
$5.86
$12.39
Impairments for 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result
of revisions to estimated abandonment costs and lower forecasted commodity prices. Impairments in 2013 primarily related to
a second LNG production train in E.G., the Ozona development in the Gulf of Mexico and our Powder River asset in Wyoming.
See Item 8. Financial Statements and Supplementary Data - Note 13 to the consolidated financial statements for information
about these impairments.
48
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to
increase or decrease in relation to revenues and sales volumes. Taxes other than income increased $61 million in 2014 from
2013, consistent with similar increases in the North America E&P Segment.
(In millions)
Production and severance
Ad valorem
Other
Total
Year Ended December 31,
2014
2013
$
$
240 $
74
92
406 $
202
61
82
345
Net interest and other decreased $40 million in 2014 from 2013 primarily due to an increase in capitalized interest, higher
net foreign currency gains and a dividend received in 2014 from a mutual insurance company of which we are an owner. See
Item 8. Financial Statements and Supplementary Data - Note 8 to the consolidated financial statements for more detailed
information.
Provision for income taxes reflects an effective tax rate of 29% and 61% for each of 2014 and 2013. See Item 8. Financial
Statements and Supplementary Data - Note 9 to the consolidated financial statements for a discussion of the effective income
tax rate.
Discontinued operations is presented net of tax. We closed the sale of our Angola assets and our Norway business in
2014, and both are reflected as discontinued operations and excluded from the International E&P segment in 2014 and 2013.
Included in discontinued operations for 2014 are after-tax gains of $532 million and $976 million related to the dispositions of
Angola and Norway, respectively. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated
financial statements.
Segment Results: 2014 compared to 2013
Segment income for 2014 and 2013 is summarized and reconciled to net income in the following table.
(In millions)
North America E&P
International E&P
Oil Sands Mining
Segment income
Items not allocated to segments, net of income taxes
Income from continuing operations
Discontinued operations
Net income
Year Ended December 31,
2014
2013
$
$
693
568
235
1,496
(527)
969
2,077
3,046
$
$
529
758
206
1,493
(562)
931
822
1,753
North America E&P segment income increased $164 million in 2014 compared to 2013. The increase was largely due to
increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford, Bakken and Oklahoma Resource Basins and lower
exploration expenses, partially offset by lower average price realizations.
International E&P segment income decreased $190 million in 2014 compared to 2013. The decrease was primarily due to
lower liquid hydrocarbon net sales volumes and lower average price realizations partially offset by a decrease in the taxes
related to Libya, a high tax jurisdiction. Also, other operating expenses were higher in 2014 primarily due to the impact of a
settlement related to the calculation of the net profits interest payments associated with our Alba Plant equity interests in E.G.
Oil Sands Mining segment income increased $29 million in 2014 compared to 2013. This increase was primarily a result
of higher operating expenses in 2013 related to a turnaround.
49
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. The substantial decline in commodity prices that began in the second half of 2014 and continued into
2016 adversely affected our cash flows. In response to the lower commodity price environment, actions undertaken to protect
our liquidity and capital structure include:
• Decreased our quarterly dividend from $0.21 to $0.05 per share, saving $425 million of cash on an annualized
basis
•
Scaled back our conventional exploration program to focus on our U.S. unconventional resources plays
• Reduced cash capital expenditures to $3.476 billion, a 33% decrease compared to 2014
• Announced a 2016 Capital Program of $1.4 billion
•
Improved cost structure by reducing North America and International E&P production expenses 24% versus
2014
• Expect future G&A costs to be lower by $160 million on an annualized basis as a result of 2015 workforce
reductions
•
•
Issued $2 billion aggregate principal amount of unsecured senior notes, $1 billion of which was used to repay
the 0.90% senior notes that matured in November 2015
Increased the capacity of the revolving credit facility from $2.5 billion to $3.0 billion while also extending the
maturity date an additional year to May 2020
• Repatriated Canadian earnings in a tax efficient manner, providing $250 million of cash available for use in
U.S. operations
• Divested of certain non-core assets resulting in net proceeds of $225 million
At December 31, 2015, we had approximately $4.2 billion of liquidity consisting of $1.2 billion in cash and cash
equivalents and $3.0 billion availability under our revolving credit facility. As previously discussed in Outlook, we are
targeting a $1.4 billion Capital Program for 2016. Given our objective of spending within our cash flow in 2016, we are
evaluating and we will continue to evaluate our options, which include our non-core asset disposition program, the flexibility to
adjust our Capital Program or to seek to raise additional capital through the issuance of debt or equity securities. We will also
continue to drive the fundamentals of expense management, including organizational capacity and operational reliability.
50
Cash Flows
The following table presents sources and uses of cash and cash equivalents for 2015, 2014 and 2013:
(In millions)
Sources of cash and cash equivalents
Continuing operations
Discontinued operations
Disposals of assets
Maturities of short-term investment
Borrowings, net
Other
Total sources of cash and cash equivalents
Uses of cash and cash equivalents
Cash additions to property, plant and equipment
Purchases of short-term investments
Investing activities of discontinued operations
Acquisitions
Purchases of common stock
Commercial paper, net
Debt repayments
Debt issuance costs
Dividends paid
Other
Total uses of cash and cash equivalents
Year Ended December 31,
2014
2013
2015
$
$
$
$
1,565
—
225
925
1,996
91
4,802
$
$
(3,476) $
(925)
—
—
—
—
(1,069)
(19)
(460)
(30)
(5,979) $
4,736
751
3,760
—
—
214
9,461
$
$
(5,160) $
—
(376)
(21)
(1,000)
(135)
(68)
—
(543)
(24)
(7,327) $
4,388
882
450
—
—
189
5,909
(4,443)
—
(550)
(74)
(500)
(65)
(182)
—
(508)
(7)
(6,329)
Cash flows from continuing operations in 2015 were lower than 2014 primarily as a result of commodity prices declines,
which were partially offset by increased net sales volumes in the North America E&P segment. Cash flows from continuing
operations in 2014 were higher than in 2013 due to increased net sales volumes in the North America E&P segment and lower
cash tax payments (primarily Libya, a higher tax jurisdiction), partially offset by lower average price realizations in all
segments, as well as lower net sales volumes in the International E&P segment.
Cash flows from discontinued operations primarily related to our Norway business, which we disposed of in the fourth
quarter of 2014.
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. Disposals in 2014 primarily
reflect the proceeds from the sales of our Angola assets and our Norway business. In 2013, net proceeds were primarily related
to the sales of our interests in Alaska, the Neptune gas plant and the DJ Basin. Disposition transactions are discussed in further
detail in Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements.
51
Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. See Liquidity and Capital
Resources below for additional information. In November 2015, we repaid our $1 billion 0.90% senior notes upon maturity.
In October 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional
information.
Additions to property, plant and equipment are our most 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 2015, 2014 and 2013:
(In millions)
North America E&P
International E&P
Oil Sands Mining (a)
Corporate
Total capital expenditures
Change in capital expenditure accrual
Additions to property, plant and equipment
Year Ended December 31,
2014
2013
2015
2,553
368
(10)
25
2,936
540
3,476
$
$
4,698
534
212
51
5,495
(335)
5,160
$
$
3,649
456
286
58
4,449
(6)
4,443
$
$
(a) Reflects reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment.
Quest CCS was successfully completed and commissioned in the fourth quarter of 2015.
During 2014, we acquired 29 million shares at a cost of $1 billion and in 2013 acquired 14 million shares at a cost of $500
million. There were no share repurchases in 2015.
See Item 8. Financial Statements and Supplementary Data – Note 23 to the consolidated financial statements for discussion
of purchases of common stock.
Liquidity and Capital Resources
On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the
following series:
•
•
•
$600 million of 2.70% senior notes due June 1, 2020
$900 million of 3.85% senior notes due June 1, 2025
$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We used the aggregate net
proceeds to repay our $1 billion 0.90% senior notes on November 2, 2015, and the remainder for general corporate purposes.
In May 2015, we amended our $2.5 billion Credit Facility to increase the facility size by $500 million to a total of $3.0
billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The
amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase
the commitment amount by up to an additional $500 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. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit
Facility, remain unchanged.
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, capital market
transactions, our committed revolving credit facility and sales of non-core assets. Our working capital requirements are
supported by these sources and we may issue either commercial paper backed by our $3.0 billion revolving credit facility or
draw on our $3.0 billion 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. Because of the
alternatives available to us as discussed above, we believe that our short-term and long-term liquidity is 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. A downgrade in 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 unsecured revolving credit facility, restrict
our access to the commercial paper market, or require us to post letters of credit or other forms of collateral for certain
52
obligations. See Item 1A. Risk Factors for a further discussion of how a downgrade in our credit ratings, particularly below
investment grade, could affect us.
We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for
general corporate or other purposes. A higher level of indebtedness could increase the risk that our liquidity and financial
flexibility deteriorates. See Item 1A. Risk Factors for a further discussion of how our level of indebtedness could affect us.
Capital Resources
Credit Arrangements and Borrowings
At December 31, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our
U.S. commercial paper program that is backed by the revolving credit facility.
At December 31, 2015, we had $7.3 billion in long-term debt outstanding. 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 "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
from time to time.
Asset Disposals
We are targeting to generate $750 million to $1 billion from select non-core asset sales. During 2015, we closed or
announced asset sales in excess of $300 million (before closing adjustments) from this program by divesting of certain operated
and non-operated producing properties in the Gulf of Mexico and natural gas assets in East Texas, North Louisiana and
Wilburton, Oklahoma. See Note 5 to the consolidated financial statements for additional discussion of these dispositions.
Cash-Adjusted Debt-To-Capital Ratio
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 25% at
December 31, 2015 and 16% at December 31, 2014.
(Dollars in millions)
Long-term debt due within one year
Long-term debt
Total debt
Cash and cash equivalents
Equity
Calculation
Total debt
Minus cash and cash equivalents
Total debt minus cash and cash equivalents
Total debt
Plus equity
Minus cash and cash equivalents
Total debt plus equity minus cash, cash equivalents
Cash-adjusted debt-to-capital ratio
Capital Requirements
Capital Spending
$
$
$
$
$
$
$
2015
2014
1
7,276
7,277
1,221
18,553
7,277
1,221
6,056
7,277
18,553
1,221
24,609
$
$
$
$
$
$
$
1,068
5,295
6,363
2,398
21,020
6,363
2,398
3,965
6,363
21,020
2,398
24,985
25%
16%
Our approved Capital Program for 2016 is $1.4 billion. Additional details were previously discussed in Outlook.
Share Repurchase Program
The remaining share repurchase authorization as of December 31, 2015 is $1.5 billion.
Other Expected Cash Outflows
On January 27, 2016, our Board of Directors approved a dividend of $0.05 per share for the fourth quarter of 2015. The
dividend is payable on March 10, 2016 to shareholders on record on February 17, 2016. The fourth quarter dividend is
consistent with the third quarter of 2015, which was a reduction as compared to the quarterly dividends of $0.21 per share for
each of the first and second quarters. We reduced the dividend as as we continue to address the uncertainty of a lower for
53
longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle and
provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.
We plan to make contributions of up to $62 million to our funded pension plans during 2016. Cash contributions to be paid
from our general assets for the unfunded pension and postretirement plans are expected to be approximately $8 million and $21
million in 2016.
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing
contracts as of December 31, 2015.
(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 (g)
Total purchase obligations
Other long-term liabilities reported in the
consolidated balance sheet(e)
Total contractual cash obligations(f)
Total
2016
2017-
2018
2019-
2020
Later
Years
$
$
11,870
178
382
761
1,768
270
141
3,322
365
30
263
90
256
119
26
754
$
$
2,196
52
$
1,354
50
70
128
495
151
29
873
37
37
393
—
30
497
7,955
46
12
506
624
—
56
1,198
253
9,452
Includes anticipated cash payments for interest of $365 million for 2016, $660 million for 2017-2018, $526 million for 2019-2020 and $3,018 million for
the remaining years for a total of $4,569 million.
618
15,988
113
2,014
158
3,279
94
1,243
$
$
$
$
$
(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)
(e)
(d)
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, 2015 our
minimum commitment would be $163 million.
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding
requirements through 2025. 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 $1,635
million. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements.
(g) We expect to make severance payments of approximately $8 million in 2016 related to the workforce reduction in 2015.
(f)
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, 2015, 2014 and 2013 aggregated $53 million, $101 million and $119 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 insure our
payments for outstanding company debt and future abandonment liabilities.
54
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.
Legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to materially
adversely impact our business, financial condition, results of operations and cash flows, including costs of compliance and
permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time
because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the
measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our
customers. For additional information see Item 1A. Risk Factors.
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
The estimation of quantities of net reserves is a highly technical process performed by our engineers for crude oil and
condensate, NGLs and natural gas and by outside consultants for synthetic crude oil, which is based upon several underlying
assumptions that are subject to change. Estimates of reserves may change, either positively or negatively, 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. The data for a
given reservoir may also change substantially 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. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Reserve estimates are based upon an unweighted average of commodity prices in the prior 12-month period, using the closing
prices on the first day of each month. Further reductions in commodity prices could have a material effect on the quantity and
present value of our proved reserves and could also cause further reductions to our near term capital programs which would
defer investment until prices improved. A shifting of capital expenditures into future periods outside of five years from the
initial proved reserve booking could potentially lead to a reduction in proved undeveloped reserves.
Our December 31, 2015 proved reserves were calculated using the SEC pricing. The table below provides the 2015 SEC
pricing for certain of the benchmark prices as well as the unweighted average for the first two months of 2016:
55
WTI Crude oil
Henry Hub natural gas
Brent crude oil
Natural gas liquids
Unweighted 12-month
2015 Average
Unweighted 2-month
2016 Average
$
$
$
$
50.28 $
2.59 $
54.25 $
17.32 $
34.19
2.28
34.86
12.87
When determining the December 31, 2015 proved reserves for each property, the benchmark prices listed above were
adjusted using price differentials that account for property-specific quality and location differences.
Beginning in the second half of 2014, the crude oil and Henry Hub benchmarks began to decline and these declines
continued through 2015 and into 2016. Commodity prices are likely to remain volatile based on global supply and demand and
could decline further. Sustained reduced commodity prices could have a material effect on the quantity and future cash flows of
our proved reserves. For further discussion of risks associated with our estimation of proved reserves, see Part I. Item 1A Risk
Factors.
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, natural gas and synthetic crude oil reserves.
The existence and the estimated amount of reserves 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. Additionally, both the expected future cash flows to be generated
by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income
available to realize deferred tax assets also rely, in part, on estimates of quantities of net reserves. Accordingly, a decline in
estimates of quantities of net proved reserves could cause us to perform an impairment analysis to determine if the carrying
value exceeds the fair value and could result in an impairment charge. In addition, a decline in estimates of quantities of net
proved reserves could prompt a goodwill impairment analysis of our International E&P segment before or after our annual test
at April 1.
Depreciation and depletion of crude oil and condensate, NGLs, natural gas and synthetic crude oil 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 been significant to the depreciation and depletion rate to any of our segments over the
past three years, any reduction in proved reserves, especially as a result of lower commodity prices, 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 2015 proved reserves based on 2015 production.
Impact of a Ten% Increase in
Proved Reserves
Impact of a Ten% Decrease in
Proved Reserves
(In millions, except per boe)
North America E&P
International E&P
Oil Sands Mining
Asset Retirement Obligations
DD&A per boe
$
$
$
(2.20) $
(0.63) $
(1.04) $
Pretax Income
216
27
17
DD&A per boe
2.69
$
0.77
$
1.46
$
Pretax Income
$
$
$
(264)
(33)
(24)
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, including bitumen mining 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 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
56
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. See Item 8. Financial Statements and Supplementary Data – Note 18 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.
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 15 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, natural gas or synthetic crude oil, sustained declines in our common
stock, reductions to our Capital 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 for our North
America E&P and International E&P assets and at the project level for OSM assets. 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 2015, we determined that the substantial decline in
commodity prices and the resulting change in future commodity price assumptions was a triggering event which required us to
57
reassess long-lived assets related to oil and gas producing properties for impairment. We estimated the fair values using an
income approach and recognized impairments during 2015. Commodity prices are one of the most significant inputs into our
models. A further decline in our commodity price assumptions could result in additional future impairment charges. See
Item 8. Financial Statements and Supplementary Data Note 13 and Note 15 to the consolidated financial statements for
discussion of impairments recorded in 2015, 2014 and 2013 and the related fair value measurements.
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, natural gas and synthetic crude oil 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, natural gas and synthetic crude oil prices and estimates of such future prices
are inherently imprecise.
• Estimated quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil. Such quantities are
based on a combination of proved and risk-weighted probable reserves such that the combined volumes represent the
most likely expectation of recovery.
• Expected timing of production. Production forecasts are the outcome of engineer 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 reasonable. However, actual
results may differ from these projections. A further sustained decline in commodity prices may cause us to reassess our long-
lived assets for impairment, and could result in future non-cash impairment charges as a result of such impairment assessments.
An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous
assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, drilling and
development costs and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the
above listed assumptions may be offset by favorable adjustments in other assumptions.
Impairment Assessments of Goodwill
Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances
change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested
for impairment at the reporting unit level. After we performed our annual impairment test in April 2015, there was a continued
decline in commodity prices as discussed above. Downward revisions to forecasted commodity price assumptions and
sustained price declines in our common stock were triggering events which required us to reassess our goodwill for impairment
as of September 30 and December 31, 2015. Based on the results of these assessments, we fully impaired the goodwill
associated with our N.A. E&P reporting unit. While the fair value of our International E&P reporting unit exceeded book value
at December 31, 2015, subsequent commodity price and/or common stock price declines may cause us to reassess our goodwill
for impairment and could result in a non-cash impairment charge in the future.
We estimated the fair values of the North America E&P and International E&P reporting units 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. The income
approach calculated the present value of expected future cash flows, which were 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. 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
58
determinations of whether or not an impairment is indicated. See Item 8. Financial Statements and Supplementary Data Note
14 to the consolidated financial statements for additional discussion of the goodwill impairment recorded in 2015.
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 15 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.
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.
We have recorded deferred tax assets and liabilities for temporary differences between book basis and tax basis, tax credit
carryforwards and operating loss carryforwards. We routinely assess the realizability of our deferred tax assets 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. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of
evidence concerning the realization of the deferred tax asset. We must consider any prudent and feasible tax planning strategies
that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized
against deferred tax assets, if we can implement the strategies and if we expect to implement them in the event the forecasted
conditions actually occur. Assumptions related to the permanent reinvestment of the earnings of our foreign subsidiaries are
reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile. In the second
quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S.
as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of approximately $1 billion
associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none our foreign earnings
remain permanently reinvested abroad.
Our net deferred tax assets, after valuation allowances, are expected to be realized through our future taxable income and
the reversal of temporary differences. Numerous judgments and assumptions are inherent in the estimation of future taxable
income, including factors such as future operating conditions (particularly liquid hydrocarbon, natural gas and synthetic crude
oil prices) and the assessment of the effects of foreign taxes on our U.S. federal income taxes. The estimates and assumptions
used in determining future taxable income are consistent with those used in our planning and capital investment reviews. We
consider a combination of reserve categories related to our existing producing properties, as well as estimated quantities of
crude oil and condensate, NGLs, natural gas and synthetic crude oil related to undeveloped discoveries if, in our judgment, it is
likely that development plans will be approved in the foreseeable future. Assumptions regarding our ability to realize the U.S.
federal benefit of foreign tax credits are based on certain estimates concerning future operating conditions (particularly crude
oil and condensate, NGLs, natural gas and synthetic crude oil prices), future financial conditions, income generated from
foreign sources and our tax profile in the year that such credits may be claimed. A sustained decline in commodity prices could
cause us to record a valuation allowance against our deferred tax assets and U.S. federal benefit of foreign tax credits.
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
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.
59
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 4.04% for our U.S. pension plans and 4.36% 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
Obligation
Expense
Impact of a 0.25% Decrease in
Discount Rate
Obligation
Expense
U.S. pension plans
Other U.S. postretirement benefit plans
$
$
(14) $
(6) $
(1) $
— $
14
7
$
$
1
—
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 6.75%
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 20 to the consolidated financial statements includes detailed
information about the assumptions used to calculate the components of our annual defined benefit pension and other
postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the
consolidated balance sheets.
Contingent Liabilities
We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes 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.
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, natural gas and synthetic crude
oil 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 15 and 16 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.
60
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 2015 and 2013 were impacted by crude oil derivatives related to a portion of our North America E&P
crude oil sales. There were no crude oil derivatives in 2014. The table below provides a summary of open positions as of
December 31, 2015:
Financial Instrument
Weighted Average Price Barrels per day
Remaining Term
Three-Way Collars
Ceiling
Floor
Sold put
Ceiling
Floor
Sold put
Ceiling
Floor
Sold put
Sold Call Options
$60.03
$50.20
$41.60
$71.84
$60.48
$50.00
$73.13
$65.00
$50.00
$72.39
10,000
January - March 2016 (a)
12,000
January- December 2016
2,000
January- June 2016 (b)
10,000
January- December 2016 (c)
(a)
Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted
average price as the underlying three-way collars.
(b) Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted
(c)
average price as the underlying three-way collars.
Call options settle monthly.
The table below provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a
hypothetical 10% change in NYMEX WTI prices on our open commodity derivatives as of December 31, 2015:
(In millions)
Crude oil commodity derivatives
Interest Rate Risk
Hypothetical Price
Increase of 10%
Hypothetical Price
Decrease of 10%
(8)
5
At December 31, 2015, our portfolio of long-term debt was substantially comprised of fixed rate instruments. We currently
manage our exposure to interest rate movements by utilizing interest rate swap agreements that effectively convert a portion of
our fixed rate debt to floating interest rate debt. As of December 31, 2015, we had multiple interest rate swap agreements with a
total notional of $900 million designated as fair value hedges.
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
financial assets and liabilities as of December 31, 2015, is provided in the following table.
61
Fair Value
Incremental
Change in
Fair Value
(In millions)
Financial assets (liabilities): (a)
Interest rate swap agreements
Long-term debt, including amounts due within one year
Fair values of cash and cash equivalents, receivables, commercial paper, 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.
8
(6,723)
2
(307)
$
$
$
$
(b)(c)
(a)
(b)
(c)
(b)
Counterparty Risk
We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices remain at or
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.
62
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
64
64
65
66
67
68
69
70
71
105
106
63
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/ John R. Sult
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, 2015.
The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2015 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/ John R. Sult
Executive Vice President and Chief Financial Officer
64
Report of Independent Registered Public Accounting Firm
To the Stockholders of Marathon Oil Corporation:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material
respects, the financial position of Marathon Oil Corporation and its subsidiaries (the “Company”) at December 31, 2015 and
2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,
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, 2015, based on
criteria established in Internal Control - Integrated Framework - 2013 issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). The Company's management is responsible for these 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 these financial statements and on the Company's internal control over financial
reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the
risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
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 25, 2016
65
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
Income (loss) from continuing operations before income taxes
Provision (benefit) for income taxes
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Per Share Data
Basic:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Diluted:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Dividends
Weighted average shares:
Basic
Diluted
$
$
$
$
$
$
$
$
$
Year Ended December 31,
2014
2013
2015
$
4,951
571
145
120
74
5,861
1,694
569
438
1,318
2,957
752
234
590
8,552
(2,691)
(267)
(2,958)
(754)
(2,204)
—
(2,204) $
(3.26) $
— $
(3.26) $
(3.26) $
— $
(3.26) $
$
0.68
677
677
$
8,736
2,110
424
(90)
78
11,258
2,246
2,105
462
793
2,861
132
406
654
9,659
1,599
(238)
1,361
392
969
2,077
3,046
1.42
3.06
4.48
1.42
3.04
4.46
0.80
680
683
$
$
$
$
$
$
$
$
9,246
2,079
423
(29)
64
11,783
2,156
2,076
389
891
2,500
96
345
659
9,112
2,671
(278)
2,393
1,462
931
822
1,753
1.32
1.17
2.49
1.31
1.16
2.47
0.72
705
709
The accompanying notes are an integral part of these consolidated financial statements.
66
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 benefit (provision)
Postretirement and postemployment plans, net of tax
Derivative hedges
Net unrecognized gain
Income tax provision
Derivative hedges, net of tax
Foreign currency translation and other
Unrealized loss
Income tax benefit (provision)
Foreign currency translation and other, net of tax
Other comprehensive income (loss)
Comprehensive income (loss)
Year Ended December 31,
2015
2014
2013
$
(2,204) $
3,046
$
1,753
228
(86)
142
—
—
—
(52)
25
(27)
1
—
1
—
—
—
142
(2,062) $
—
(1)
(1)
(27)
3,019
$
$
300
(112)
188
1
—
1
(3)
1
(2)
187
1,940
The accompanying notes are an integral part of these consolidated financial statements.
67
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 $4 and $3
Inventories
Other current assets
Total current assets
Equity method investments
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,260 and $21,884
Goodwill
Other noncurrent assets
Total assets
Liabilities
Current liabilities:
Accounts payable
Payroll and benefits payable
Accrued taxes
Other current liabilities
Long-term debt due within one year
Total current liabilities
Long-term debt
Deferred tax liabilities
Defined benefit postretirement plan obligations
Asset retirement obligations
Deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Stockholders’ Equity
Preferred stock - no shares issued or outstanding (no par value,
26 million shares authorized)
Common stock:
Issued – 770 million shares (par value $1 per share, 1.1 billion shares authorized)
Securities exchangeable into common stock – no shares issued
or outstanding (no par value, 29 million shares authorized)
Held in treasury, at cost – 93 million and 95 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.
68
December 31,
2015
2014
$
$
1,221
912
313
144
2,590
1,003
27,061
115
1,542
32,311
1,313
133
132
150
1
1,729
7,276
2,441
403
1,601
308
13,758
—
770
—
(3,554)
6,498
14,974
(135)
18,553
32,311
$
2,398
1,729
357
109
4,593
1,113
29,040
459
778
35,983
2,545
191
285
290
1,068
4,379
5,295
2,486
598
1,917
288
14,963
—
770
—
(3,642)
6,531
17,638
(277)
21,020
35,983
$
$
$
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,
2014
2013
2015
$
(2,204) $
3,046
$
1,753
Discontinued operations
Deferred income taxes
Depreciation, depletion and amortization
Impairments
Pension and other postretirement benefits, net
Exploratory dry well costs and unproved property impairments
Net (gain) loss on disposal of assets
Equity method investments, net
Changes in:
Current receivables
Inventories
Current accounts payable and accrued liabilities
All other operating, net
Net cash provided by continuing operations
Net cash provided by discontinued operations
Net cash provided by operating activities
Investing activities:
Acquisitions, net of cash acquired
Additions to property, plant and equipment
Disposal of assets
Investments - return of capital
Investing activities of discontinued operations
Purchases of short term investments
Maturities of short term investments
All other investing, net
Net cash used in investing activities
Financing activities:
Commercial paper, net
Borrowings
Debt issuance costs
Debt repayments
Purchases of common stock
Dividends paid
All other financing, net
Net cash provided by (used in) financing activities
Effect of exchange rate changes on cash:
Continuing operations
Discontinued operations
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.
69
—
(806)
2,957
752
1
1,214
(120)
33
817
36
(965)
(150)
1,565
—
1,565
—
(3,476)
225
77
—
(925)
925
(28)
(3,202)
—
1,996
(19)
(1,069)
—
(460)
14
462
(2)
—
(1,177)
2,398
1,221
$
(2,077)
88
2,861
132
(34)
623
90
27
119
(11)
(33)
(95)
4,736
751
5,487
(21)
(5,160)
3,760
61
(376)
—
—
(10)
(1,746)
(135)
—
—
(68)
(1,000)
(543)
153
(1,593)
(2)
(12)
2,134
264
2,398
$
(822)
(34)
2,500
96
45
720
29
12
217
(19)
(208)
99
4,388
882
5,270
(74)
(4,443)
450
61
(550)
—
—
35
(4,521)
(65)
—
—
(182)
(500)
(508)
93
(1,162)
(3)
(4)
(420)
684
264
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity
Preferred
Stock
Common
Stock
Total Equity of Marathon Oil Stockholders
Securities
Exchangeable
into Common
Stock
Additional
Paid-in
Capital
Treasury
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Total
Equity
$
— $
770
$
— $ (2,560) $
6,616
$ 13,890
$
(433) $ 18,283
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
170
(513)
—
—
—
—
(44)
—
20
—
—
—
—
—
—
1,753
—
(508)
—
—
—
—
183
—
126
(513)
20
1,753
183
(508)
$
— $
770
$
— $ (2,903) $
6,592
$ 15,135
$
(250) $ 19,344
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
276
(1,015)
—
—
—
—
(57)
—
(4)
—
—
—
—
—
—
3,046
—
(543)
—
—
—
—
(27)
—
219
(1,015)
(4)
3,046
(27)
(543)
$
— $
770
$
— $ (3,642) $
6,531
$ 17,638
$
(277) $ 21,020
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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
Preferred
Stock
Common
Stock
Securities
Exchangeable
into Common
Stock
Treasury
Stock
—
—
—
—
—
—
—
—
—
—
770
—
—
770
—
—
770
—
—
770
—
—
—
—
—
—
—
—
—
—
63
(4)
14
73
(7)
29
95
(2)
—
93
(In millions)
December 31, 2012 Balance
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net income
Other comprehensive income
Dividends paid
December 31, 2013 Balance
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net income
Other comprehensive loss
Dividends paid
December 31, 2014 Balance
Shares issued - stock-based
compensation
Shares repurchased
Stock-based compensation
Net loss
Other comprehensive income
Dividends paid
December 31, 2015 Balance
(Shares in millions)
December 31, 2012 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2013 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2014 Balance
Shares issued - stock-based
compensation
Shares repurchased
December 31, 2015 Balance
The accompanying notes are an integral part of these consolidated financial statements.
70
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.; and oil sands mining, bitumen transportation and upgrading, and marketing of synthetic crude oil and vacuum gas oil in
Canada.
Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned,
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.
Equity method investments are included as noncurrent assets on the consolidated balance sheet. These investments are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is
deemed to be other than temporary. When the loss is deemed to be 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 net income. Differences in
the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the
remaining useful lives of the underlying assets, except for the excess related to goodwill.
Discontinued operations – Disclosures in this report related to results of operations and cash flows are presented on the
basis of continuing operations unless otherwise stated. As a result of the sale of our Angola assets and our Norway business in
2014 (see Note 5), these businesses are reflected as discontinued operations in the periods prior to and including 2014.
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.
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
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. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic
crude oil.
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. Uncollectible accounts receivable are
reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected and the
amount of any reserve may be reasonably estimated.
71
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Inventories – Crude oil and natural gas inventories are recorded at weighted average cost and carried at the lower of cost or
market value. Materials and supplies inventory 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.
During the fourth quarter of 2015, we elected to change our accounting method related to our U.S. crude oil and natural gas
inventories from last in, first out ("LIFO") method to weighted average cost. At December 31, 2015, this inventory represented
$5 million of our total inventory value, see Note 10 to the consolidated financial statements for additional detail related to
inventories. We believe this change is preferable as it provides consistent application of the cost basis for all categories of
inventories across our worldwide portfolio, more accurately reflects the current value of inventory which provides for a better
matching of expenses to revenues, and enhances comparability to our peers.
The effect of changing the method from LIFO to weighted average cost was immaterial for all current and prior periods.
We recorded the cumulative effect of this change within our Consolidated Balance Sheets and Consolidated Statements of
Income during the fourth quarter of 2015 and did not adjust previously reported periods. This resulted in an increase in our
Inventories account of $2 million and a decrease in Production costs by $2 million. The change in method had an immaterial
impact to income from continuing operations, with no change to basic or diluted earnings per share.
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, interest
rate risk and foreign currency exchange 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 and foreign currency forwards to manage our exposure to changes in the value of foreign
currency denominated tax liabilities. 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.
Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives
used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce.
Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.
Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and
market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to
our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage
counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their
financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting
period. If significant transfers occur, they would be disclosed in Note 15 to the consolidated financial statements.
Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities,
which include bitumen mining and upgrading.
Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties or in oil sands mines, to drill
and equip exploratory wells in progress and those that find proved reserves, to drill and equip development wells and to
construct or expand oil sands mines and upgrading facilities 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.
72
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties, which include
bitumen mining and upgrading facilities, 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, mine equipment and infrastructure
Range of Useful Lives
3 to 15 years
10 to 40 years
1 to 40 years
Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells,
development costs and our bitumen mining and upgrading facilities, 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. 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, the expense is reported in exploration expenses.
Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any
gains or losses are reported in net 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 when the assets are
classified as held for 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.
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, which include our bitumen mining facilities. Asset retirement obligations
for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, 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 structure, depth of water, reservoir characteristics, depth of the
reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering
professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing
facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement
obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen
73
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are
indeterminate.
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 reserves for oil and gas
production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.
Deferred income taxes – Deferred tax assets and liabilities 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 our expectation to generate sufficient future
taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent
regarding the permanent reinvestment of the income from foreign subsidiaries.
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.
2. Accounting Standards
Not Yet Adopted
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable
value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the
first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We 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 May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all
investments for which fair value is measured using the net asset value per share practical expedient. The amendment also
removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per
share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net
asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will be applied on a
retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no
impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest
entity ("VIE"). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE.
However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when
decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity
assesses if the equity holders at risk lack decision making rights. This standard is effective for us for annual periods beginning
after December 15, 2015 and early adoption is permitted, including in interim periods. We 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 August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going
concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is
effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to
have a significant impact on our consolidated results of operations, financial position or cash flows.
74
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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 should be applied retrospectively to each prior reporting period presented or with the
cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. 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 November 2015, the FASB issued an update that requires an entity to classify deferred income tax liabilities and assets
as noncurrent in a classified statement of financial position. The amendments are effective for us in the first quarter of 2017
and early adoption is permitted. We elected to early adopt these amendments in the fourth quarter of 2015 on a prospective
basis. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or
cash flows.
In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct
reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and early adoption is
permitted. We elected to early adopt these amendments in the fourth quarter of 2015 on a retrospective basis. Adoption of this
standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued
operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in
operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the
organization’s operations and financial results. Expanded disclosures about the assets, liabilities, income and expenses of
discontinued operations are required. In addition, disclosure of the pretax income attributable to a disposal of a significant part
of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with
information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective
for us in the first quarter of 2015. Adoption of this standard did not have a significant impact on our consolidated results of
operations, financial position or cash flows.
3. Variable Interest Entities
The owners of the AOSP, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a
publicly traded Canadian limited partnership ("Corridor Pipeline") to provide materials transportation capabilities among the
Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by
a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its
undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $2 million current liability
recorded at December 31, 2015 and $3 million at December 31, 2014. Under this agreement, the AOSP absorbs all of the
operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended,
by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all
remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies
as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are
not the primary beneficiary because our shipments are only 20% of the total; therefore the Corridor Pipeline is not consolidated
by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the
contract term, which was $447 million as of December 31, 2015. The liability on our books related to this contract at any given
time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum
exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any
guarantees of such assistance in the future.
4. Acquisitions
2014 - North America E&P
In the fourth quarter of 2014, we acquired additional acres in the SCOOP, at a cost of $58 million after final settlement
adjustments.
75
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
In the third quarter of 2014, we acquired acreage in the Oklahoma Resource Basins at a cost of $68 million after final
settlement adjustments.
2013 - North America E&P
In July 2013, we acquired additional acreage in the Eagle Ford in a transaction valued at $97 million, including a carried
interest of $23 million which was fully satisfied in 2014. The transaction was accounted for as a business combination, with the
entire up-front cash consideration of $74 million allocated to property, plant and equipment at the acquisition date.
The fair values of assets acquired and liabilities assumed in the business combination were measured primarily using an
income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant
inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated
reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future
operating and development costs and a discount rate of approximately 10%. The pro forma impact of these transactions,
individually and in the aggregate, is not material to our consolidated statements of income for any periods presented.
5. Dispositions
2015 - North America E&P Segment
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. Assets held for sale in the December 31, 2015 consolidated balance sheet were related to the Neptune
field that was pending at that date and included $31 million in total assets and $54 million of total liabilities. 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 15).
2015 - International E&P Segment
In September 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. The Kenya transaction closed in February 2016 and the Ethiopia
transaction is expected to close in the first quarter of 2016. Cash proceeds for both transactions are expected to be $10 million,
before closing adjustments.
2014 - North America E&P Segment
In June 2014, we closed the sale of non-core acreage located in the far northwest portion of the Williston Basin for
proceeds of $90 million. A pretax loss of $91 million was recorded in the second quarter of 2014.
2014 - International E&P Segment
In June 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim FPSO, 10
operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea. The transaction
closed in the fourth quarter of 2014 for proceeds of $2.1 billion, before netting $589 million cash transferred to the buyer. A
$976 million after-tax gain on the sale of Norway business was recorded in the fourth quarter of 2014. Included in this after-tax
gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation
allowance.
Our Norway business is reflected as discontinued operations in the consolidated statements of income and the consolidated
statements of cash flows for the periods prior to and including 2014. Select amounts reported in discontinued operations were
as follows:
(In millions)
Revenues applicable to discontinued operations
Pretax income from discontinued operations
Pretax gain on disposition of discontinued operations
Year Ended December 31,
2014
2013
$
$
$
1,981
1,693
1,406
$
$
$
3,176
2,537
—
76
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
In the first quarter of 2014, we closed the sales of our 10% non-operated working interests in the Production Sharing
Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. A
$532 million after-tax gain on the sale of our Angola assets was recorded in 2014. Included in this after-tax gain is a deferred
tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.
Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the
consolidated statements of cash flows for the periods prior to and including 2014. Select amounts reported in discontinued
operations were as follows:
(In millions)
Revenues applicable to discontinued operations
Pretax income from discontinued operations
Pretax gain on disposition of discontinued operations
2013 - North America E&P Segment
Year Ended December 31,
2014
2013
$
$
$
58
51
426
$
$
$
361
247
—
In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million
was recorded in the second quarter of 2013.
In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax
loss was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of
$166 million. A $98 million pretax gain was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of
$50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax
gain on this sale was $55 million.
2013 - International E&P Segment
In the fourth quarter of 2013, we transferred our 45% working interest and operatorship in the Safen block in the Kurdistan
Region of Iraq at a pretax loss of $17 million.
6.
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 and stock appreciation rights in 2013, provided the effect is not
antidilutive. The per share calculations below exclude 13 million, 4 million and 5 million stock options in 2015, 2014 and 2013
that were antidilutive.
(In millions, except per share data)
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Weighted average common shares outstanding
Effect of dilutive securities
Weighted average common shares, diluted
Per basic share:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Per diluted share:
Income (loss) from continuing operations
Discontinued operations
Net income (loss)
Year Ended December 31,
2014
2013
2015
(2,204) $
—
(2,204) $
677
—
677
(3.26) $
— $
(3.26) $
(3.26) $
— $
(3.26) $
969
2,077
3,046
680
3
683
1.42
3.06
4.48
1.42
3.04
4.46
$
$
$
$
$
$
$
$
931
822
1,753
705
4
709
1.32
1.17
2.49
1.31
1.16
2.47
$
$
$
$
$
$
$
$
77
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
7. Segment Information
We have three 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:
• North America E&P ("N.A. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural
gas in North America;
•
International E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas
outside of North America and produces and markets products manufactured from natural gas, such as LNG and
methanol, in E.G.; and
• Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and
upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker
(“CODM”). Segment income represents income from continuing 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. These unallocated costs primarily consist of employment costs
(including pension effects), professional services, facilities and other costs associated with corporate and operations support
activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change,
unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability (as determined by the
CODM) also are not allocated to operating segments.
As discussed in Note 5, we closed the sale of our Angola assets in the first quarter of 2014 and our Norway business in the
fourth quarter of 2014, and both are reflected as discontinued operations and excluded from the International E&P segment for
2014 and 2013.
Year Ended December 31, 2015
(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
Exploration expenses
Depreciation, depletion and amortization
Impairments
Other expenses (a)
Taxes other than income
Net interest and other
Income tax provision (benefit)
$
N.A. E&P
3,358
$
396
3,754
—
24
Int'l E&P
728
$
103
831
157
27
724
401
362
2,377
2
462
215
—
(279)
OSM
815
72
887
—
21
715
69
—
236
5
34
18
—
(56)
Not Allocated
to Segments
50
$
—
50
(12)
122
—
—
855
49
745
440
1
267
(480)
(c)
$
(d)
(e)
(f)
(g)
(h)
(i)
Total
4,951
571
5,522
145
194
1,694
569
1,318
2,957
752
1,028
234
267
(754)
$
$
(113) $
(10) $
(1,717)
25
$
$
(2,204)
2,936
255
99
101
295
—
92
—
—
61
112
368
Segment income (loss)/Income (loss) from continuing
operations
Capital expenditures (b)
$
$
(486) $
$
2,553
Includes other operating expenses and general and administrative expenses.
Includes accruals.
(b)
(c) Unrealized gain on crude oil derivative instruments.
(d)
(a)
(e)
Partial impairment of investment in equity method investee (See Note 15).
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).
(f) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 13).
(g) Goodwill impairment (see Note 14) and proved property impairments (see Note 15).
(h)
(i)
Includes pension settlement loss of $119 million (see Note 20) and severance related expenses associated with workforce reductions of $55 million.
Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9).
78
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Year Ended December 31, 2014
(In millions)
Sales and other operating revenues
Marketing revenues
Total revenues
Income from equity method investments
Net gain (loss) on disposal of assets and other income
N.A. E&P
5,770
$
1,839
7,609
—
23
Int'l E&P
1,410
$
219
1,629
424
57
$
OSM
1,556
52
1,608
—
4
Not Allocated
to Segments
—
$
—
—
—
(96)
Less:
Production expenses
Marketing costs
Exploration expenses
Depreciation, depletion and amortization
Impairments
Other expenses (a)
Taxes other than income
Net interest and other
Income tax provision (benefit)
891
1,836
608
2,342
23
473
385
—
381
693
4,698
$
$
$
$
386
217
185
269
—
197
—
—
288
568
534
969
52
—
206
—
54
20
—
76
235
212
$
$
—
—
—
44
109
392
1
238
(353)
(527)
51
Segment income/Income from continuing operations
Capital expenditures (b)
(a)
(b)
(c)
(d)
(e)
Includes other operating expenses and general and administrative expenses.
Includes accruals.
Primarily related to the sale of non-core acreage in our North America E&P segment ( See Note 5).
Proved Property impairments (See Note 15)
Includes pension settlement loss of $99 million (See Note 20).
(c)
(d)
(e)
$
Total
8,736
2,110
10,846
424
(12)
2,246
2,105
793
2,861
132
1,116
406
238
392
969
5,495
$
$
Year Ended December 31, 2013
(In millions)
Sales and other operating revenues
Marketing revenues
Total revenues
Income from equity method investments
Net gain (loss) on disposal of assets and other income
Less:
Production expenses
Marketing costs
Exploration expenses
Depreciation, depletion and amortization
Impairments
Other expenses (a)
Taxes other than income
Net interest and other
Income tax provision (benefit)
N.A. E&P
5,068
$
1,797
6,865
—
12
Int'l E&P
2,654
$
264
2,918
427
50
797
1,796
725
1,927
41
420
318
—
324
529
3,649
$
$
359
262
166
331
—
161
—
—
1,358
758
456
$
$
OSM
1,576
18
1,594
—
5
1,000
18
—
218
—
66
22
—
69
206
286
Not Allocated
to Segments
$
(52)
—
(52)
(4)
(32)
—
—
—
24
55
401
5
278
(289)
(562)
58
$
$
Total
9,246
2,079
11,325
423
35
2,156
2,076
891
2,500
96
1,048
345
278
1,462
931
4,449
(c)
$
(d)
(e)
(f)
(g)
$
$
Includes other operating expenses and general and administrative expenses.
Includes accruals.
Segment income/Income from continuing operations
Capital expenditures (b)
(a)
(b)
(c) Unrealized loss on crude oil derivative instruments (see Note 16).
(d)
(e)
(f)
(g)
EGHoldings impairment (See Note 15).
Related to the disposal of assets from our North America E&P Segment (see Note 5).
Proved property impairments (see Note 15).
Includes pension settlement loss of $45 million (see Note 20).
Revenues from external customers are attributed to geographic areas based upon selling location. The following
summarizes revenues from external customers by geographic area.
79
$
$
$
$
$
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
(In millions)
United States
Canada
Libya(a)
Other international
Total revenues
(a)
See Note 12 for discussion of Libya operations.
Year Ended December 31,
2014
2013
2015
$
$
3,804
887
—
831
5,522
$
$
7,609
1,608
244
1,385
10,846
$
$
6,813
1,594
1,106
1,812
11,325
In 2015, sales to Irving Oil and Shell Oil and each of their respective affiliates accounted for approximately 13% and 11% of
our total revenues. In 2014, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues. In 2013,
Statoil, the purchaser of the majority of our Libyan crude oil, accounted for approximately 10% of our total revenues
Year Ended December 31,
2014
2013
2015
$
$
3,963
203
464
781
111
5,522
$
$
$
$
8,170
371
693
1,525
87
10,846
$
$
8,688
313
693
1,542
89
11,325
December 31,
2015
2014
15,353
9,197
1,917
1,597
28,064
$
$
16,518
9,802
1,949
1,884
30,153
Revenues by product line were:
(In millions)
Crude oil and condensate
Natural gas liquids
Natural gas
Synthetic crude oil
Other
Total revenues
The following summarizes property, plant and equipment and equity method investments.
(In millions)
United States
Canada
Equatorial Guinea
Other international
Total long-lived assets
80
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
8. 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 gains
Other
Total other
Net interest and other
2015
Year Ended December 31,
2014
2013
$
$
$
9
(358)
11
26
(312)
23
22
45
(267) $
$
7
(309)
12
20
(270)
21
11
32
(238) $
5
(319)
9
12
(293)
14
1
15
(278)
Foreign currency – Aggregate foreign currency gains were included in the consolidated statements of income as follows:
(In millions)
Net interest and other
Provision for income taxes
Aggregate foreign currency gains
Year Ended December 31,
2014
2013
2015
$
$
23
(11)
12
$
$
21
(12)
9
$
$
14
(2)
12
9. Income Taxes
Income tax provisions (benefits) for continuing operations were:
2015
Year Ended December 31,
2014
2013
(In millions)
Federal
State and local
Foreign
Total
Current Deferred
$
(43) $
(8)
103
52
$
$
Total
$
Current Deferred
62
(58)
84
88
15
8
281
304
$
(730) $
(26)
2
(754) $
Total
$
$
77
(50)
365
392
(687) $
(18)
(101)
(806) $
Current Deferred
$
$
83
39
1,374
$ 1,496
$
Total
(47) $
36
(6)
33
1,393
19
(34) $ 1,462
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,
2014
2013
2015
Statutory rate applied to income (loss) from continuing operations before income taxes
Effects of foreign operations, including foreign tax credits
Change in permanent reinvestment assertion
Adjustments to valuation allowances
Change in tax law
Goodwill impairment
Other
Effective income tax expense (benefit) rate on continuing operations
(35)%
(2)
—
3
5
4
—
(25)%
35%
(6)
(19)
21
—
—
(2)
29%
35%
26
—
(1)
—
—
1
61%
81
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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 7.
Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2015 and 2014 as
compared to 2013, due to a shift in pretax income mix between high and low tax jurisdictions. This is primarily related to
decreased sales in Libya in 2015 and 2014 where the tax rate is in excess of 90%. Excluding Libya, the effective tax rates on
continuing operations would be a benefit of 25% in 2015 and expense of 27% and 38% in 2014 and 2013.
Change in permanent reinvestment assertion – In the second quarter of 2015, we reviewed our operations and concluded
that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for
previously unremitted foreign earnings of approximately $1 billion associated with our Canadian operations to be permanently
reinvested outside the U.S. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to
offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes were recorded in the second quarter of
2015. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad.
In the second quarter of 2014, we reviewed our foreign operations, including the disposition of our Norway business, and
concluded that our foreign operations did not have the same level of immediate capital needs as previously expected.
Therefore, we removed our assertion for previously unremitted foreign earnings associated with our U.K. operations to be
permanently reinvested outside the U.S. The U.K. statutory tax rate was in excess of the U.S. statutory tax rate and therefore
foreign tax credits associated with these earnings exceeded any incremental U.S. tax liabilities.
Adjustments to valuation allowances – In 2015, we increased the valuation allowance against foreign tax credits because it
is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2015. Additionally, we
increased the valuation allowance on deferred tax assets associated with our foreign operations as a result of pretax losses in
certain jurisdictions. In 2014, we increased the valuation allowance against foreign tax credits as a result of removing the
permanent reinvestment assertion on our U.K. operations since the U.K. statutory tax rate is in excess of the U.S. statutory tax
rate per discussion above.
Change in tax law – On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax
rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in
the second quarter of 2015.
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
Valuation allowances:
Federal
State, net of federal benefit
Foreign
Total deferred tax assets
Deferred tax liabilities:
Property, plant and equipment
Investments in subsidiaries and affiliates
Other
Total deferred tax liabilities
Net deferred tax liabilities
Year Ended December 31,
2015
2014
$
$
260
563
17
4,335
35
17
73
(2,820)
(56)
(162)
2,262
3,376
—
105
3,481
1,219
$
$
364
245
89
4,062
—
—
116
(2,775)
(58)
(108)
1,935
3,737
66
67
3,870
1,935
Tax carryforwards – At December 31, 2015 our operating loss carryforwards includes $365 million from the U.S. that
expire in 2035. Foreign operating loss carryforwards include $863 million from Canada that expire in 2029 through 2035, $208
82
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
million from the Kurdistan Region of Iraq that expire in 2016 through 2020, $84 million from Libya that expires in 2025 and
$81 million from E.G. that expire in 2017 through 2020. State operating loss carryforwards of $1,415 million expire in 2016
through 2035. Foreign tax credit carryforwards of $3,798 million expire in 2022 through 2025.
Valuation allowances – We consider whether it is more likely than not that some portion or all of our deferred tax assets
will not be realized. In the event it is more likely than not that some portion or all of our deferred taxes will not be realized,
such assets are reduced by a valuation allowance. The estimated realizability of the benefit of our deferred tax asset is based on
certain estimates concerning future operating conditions (particularly as related to prevailing commodity prices), future
financial conditions, income generated from foreign sources and our tax profile in the years that such operating loss
carryforwards and tax credits may be claimed. Future increases to our valuation allowance are possible if our estimates and
assumptions (particularly as they relate to downward revisions of our long-term commodity price forecasts) are revised such
that they reduce estimates of future taxable income during the carryforward period.
Federal valuation allowances increased $45 million in 2015 related to U.S. benefits on foreign taxes accrued in 2015.
Federal valuation allowances decreased $222 million in 2014 primarily due to the sale of our Norway and Angola businesses.
Federal valuation allowances increased $930 million in 2013 related to U.S. benefits on foreign taxes accrued in that year.
Foreign valuation allowances increased $54 million in 2015 primarily due to deferred tax assets generated in the Kurdistan
Region of Iraq, E.G. and Gabon. Foreign valuation allowances decreased $41 million in 2014 primarily due the disposal of our
Angolan assets. Foreign valuation allowances decreased $61 million in 2013 primarily due to the disposal of our Indonesian
assets.
Net deferred tax liabilities were classified in the consolidated balance sheets as follows:
(In millions)
Assets:
Other current assets
Other noncurrent assets
Liabilities:
Other current liabilities
Noncurrent deferred tax liabilities
Net deferred tax liabilities
December 31,
2015
2014
$
$
— $
1,222
—
2,441
1,219
$
29
525
3
2,486
1,935
We elected to prospectively adopt Accounting Standards Update 2015-17, Balance Sheet Classification of Deferred Taxes,
as of December 31, 2015, as disclosed in Note 2. Under this new guidance, we classify all deferred tax assets and liabilities and
related valuation allowances as noncurrent. In accordance with a prospective adoption, we did not restate the balance sheet
classification of deferred taxes for prior periods.
We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been
completed through the 2009 tax year. In November 2015, we received Notices of Proposed Adjustment related to our
2010-2011 tax years. We anticipate receiving the final agent's report in 2016. We believe adequate provision has been made for
federal income taxes and interest which may become payable for years not yet settled. 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, 2015 our income tax returns remain subject to examination in the following major tax jurisdictions for
the tax years indicated:
United States(a)
Canada
Equatorial Guinea
Libya
United Kingdom
(a)
Includes federal and state jurisdictions.
2004-2014
2010-2014
2007-2014
2012-2014
2008-2014
83
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table summarizes the activity in unrecognized tax benefits:
(In millions)
Beginning balance
Additions for tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Statute of limitations
Ending balance
2015
2014
2013
80
—
1
—
(7)
(9)
65
$
$
146
—
11
(68)
(9)
—
80
$
$
98
14
66
(25)
(5)
(2)
146
$
$
If the unrecognized tax benefits as of December 31, 2015 were recognized, $25 million would affect our effective income
tax rate. As of December 31, 2015, there are no material uncertain tax positions for which it is reasonably possible that the
amount would significantly increase or decrease during the next twelve months.
Interest and penalties are recorded as part of the tax provision and were $1 million, $6 million and $13 million related to
unrecognized tax benefits in 2015, 2014 and 2013. As of December 31, 2015 and 2014, $14 million and $16 million of interest
and penalties were accrued related to income taxes.
Pretax income (loss) from continuing operations included amounts attributable to foreign sources of $(654) million, $1,180
million and $2,336 million in 2015, 2014 and 2013.
10. Inventories
Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or
market 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)
Liquid hydrocarbons, natural gas and bitumen
Supplies and other items
Inventories at cost
December 31,
2015
2014
$
$
35
278
313
$
$
58
299
357
11. Equity Method Investments and Related Party Transactions
During 2015, 2014 and 2013 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, 2015
60%
52%
45%
December 31,
2015
2014
603
230
169
1
1,003
$
$
693
225
194
1
1,113
$
$
Dividends and partnership distributions received from equity method investees (excluding distributions that represented a
return of capital previously contributed) were $178 million in 2015, $451 million in 2014 and $435 million in 2013.
84
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Summarized financial information for equity method investees is as follows:
(In millions)
Income data – year:
Revenues and other income
Income from operations
Net income
Balance sheet data – December 31:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
2015
2014
2013
$
1,444
849
727
$
$
$
$
769
313
280
467
1,317
211
41
1,349
826
728
639
1,451
371
39
Revenues from related parties were $51 million, $56 million and $55 million in 2015, 2014 and 2013, with the majority
related to EGHoldings in all years. Purchases from related parties were $207 million, $207 million and $242 million in 2015,
2014 and 2013 with the majority related to Alba Plant LLC in all years.
Current receivables from related parties at December 31, 2015 and 2014, were $29 million, and $31 million. Payables to
related parties were $5 million and $11 million at December 31, 2015 and 2014, with the majority related to Alba Plant LLC.
12. Property, Plant and Equipment
(In millions)
North America E&P
International E&P
Oil Sands Mining
Corporate
Net property, plant and equipment
December 31,
2015
2014
15,226
2,533
9,197
105
27,061
$
$
16,717
2,741
9,455
127
29,040
$
$
Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the
shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production
remains shut-in through early 2016. Considerable uncertainty remains around the timing of future production and sales levels.
As of December 31, 2015, our net property, plant and equipment investment in Libya is approximately $777 million, and
total proved reserves (unaudited) in Libya are 235 mmboe. We and our partners in the Waha concessions continue to assess the
situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and
equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves
anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the
carrying value of $777 million by a significant amount.
85
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Deferred exploratory well costs were 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
(In millions)
Beginning balance
Additions
Charges to expense
Transfers to development
Dispositions(a)
Ending balance
(a)
Includes sale of Angola assets and Norway business in 2014.
December 31,
2015
2014
2013
$
$
$
$
352
85
437
2
2015
610
610
(148)
(635)
—
437
$
$
$
$
484
126
610
3
2014
793
647
(45)
(579)
(206)
610
$
$
$
$
512
281
793
7
2013
617
624
(25)
(414)
(9)
793
Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2015 are
summarized by geographical area below:
(In millions)
Gabon
E.G.
Total
$
$
63
22
85
Well costs that have been suspended for longer than one year are associated with two projects. Management believes these
projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development
based on current plans.
Gabon - The Diaba-1B well reached total depth in the third quarter of 2013. Additional 3D seismic data was acquired in
2014 in the western part of the block and depth processing continued through 2015. We continue to utilize this data to facilitate
evaluation of additional resource potential on the offshore Diaba License to support decisions regarding the exploration
program, with drilling currently planned for 2017.
E.G. – The Corona well on Block D offshore E.G. was drilled in 2004, and we acquired an additional interest in the well in
2012. We plan to develop Block D through a unitization with the Alba field. Negotiations have been substantially completed
and approval is expected in 2016.
13. Impairments and Exploration Expenses
During 2015, the continued decline of commodity prices resulted in downward revisions of our long-term commodity price
assumptions and resulted in impairments of long-lived assets related to oil and gas producing properties. Further changes in
management's forecast assumptions (including our Capital Program), or continued deterioration in commodity prices may cause
us to reassess our long-lived assets and goodwill for impairment, and could result in impairment charges in the future.
Impairments
The following table summarizes impairment charges of proved properties:
(in millions)
Total impairments
Year Ended December 31,
2015
2014
2013
$
752
$
132
$
96
2015 - Impairments included $340 million million for the goodwill impairment of the North America E&P reporting unit,
$335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted
86
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and
Wilburton, Oklahoma.
2014 - Impairments of $132 million consisted primarily of proved properties in the Gulf of Mexico, Texas and North
Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices.
2013 - Impairments of $96 million included an impairment to the second LNG production train in E.G. as a result of a
change in E.G.'s natural gas policy related to the country's resources for $40 million, a $15 million impairment of our Powder
River Basin assets as a result of our decision to wind down operations and other impairments of long-lived assets as a result of
reduced drilling expectations, reductions of estimated reserves or decreased commodity prices.
See Note 7 for relevant detail regarding segment presentation, Note 14 for further detail regarding the goodwill impairment
and Note 15 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
Unproved property impairments
Year Ended December 31,
2014
2013
2015
$
$
$
964
250
31
73
$
306
317
85
85
1,318
$
793
$
572
148
80
91
891
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.
2014 - Primarily consists of Eagle Ford and Bakken leases that either expired or we decided not to drill or extend.
2013 - Primarily consists of Eagle Ford leases that either expired or we decided not to drill or extend.
See Note 7 for relevant detail regarding segment presentation of unproved property impairments.
Dry well costs
2015 - Includes the operated Solomon exploration well in the Gulf of Mexico, our operated Sodalita West #1 exploratory
well in E.G. and suspended well costs related our Canadian in-situ assets at Birchwood.
2014 - Includes the operated Key Largo well, outside-operated Perseus well and the outside operated second Shenandoah
appraisal well, all of which are located in the Gulf of Mexico. In addition, 2014 also includes our exploration programs in
Kurdistan Region of Iraq, Ethiopia and Kenya.
2013 - Primarily includes our exploration programs in Norway, Kurdistan Region of Iraq, Ethiopia, Kenya, Poland and
Gulf of Mexico.
14. Goodwill
Goodwill is tested for impairment on an annual basis as of April 1 each year, or 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 North America
E&P and International E&P include goodwill. We estimated the fair values of the North America E&P and International E&P
reporting units 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 utilized discounted cash flows, which were based on forecasted
87
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
assumptions. Key assumptions to the income approach include: future liquid hydrocarbon and natural gas prices, estimated
quantities of liquid hydrocarbon and natural gas proved and probable reserves, expected timing of production, discount rates,
future capital requirements and 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 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.
We performed our annual impairment tests as of April 1 in 2015, 2014 and 2013 and no impairment was required. The fair
value of each of our reporting units with goodwill exceeded the book value. Subsequent to our goodwill impairment test in
April 2015, triggering events (downward revisions to forecasted commodity price assumptions and sustained price declines in
our common stock) required us to reassess our goodwill for impairment as of September 30, 2015 and December 31, 2015. We
recorded an impairment of goodwill for the N.A. E&P reporting unit during the fourth quarter of 2015. While the fair value of
our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock price declines
may cause us to reassess our goodwill for impairment and could result in a non-cash impairment charge in the future.
The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount
of goodwill for 2015 and 2014:
(In millions)
2014
Beginning balance, gross
Less: accumulated impairments
Beginning balance, net
Dispositions
Ending balance, net
2015
Beginning balance, gross
Less: accumulated impairments
Beginning balance, net
Dispositions
Impairment
Ending balance, net
N.A. E&P
Int'l E&P
OSM
Total
$
$
$
$
$
$
$
347
—
347
(3)
344
344
—
344
(4)
(340)
— $
152
—
152
(37)
115
115
—
115
—
—
115
$
$
$
$
$
1,412
(1,412)
—
—
— $
$
1,412
(1,412)
—
—
—
— $
1,911
(1,412)
499
(40)
459
1,871
(1,412)
459
(4)
(340)
115
88
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
15. 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
Commodity
Interest rate
Derivative instruments, assets
Derivative instruments, liabilities
Commodity
Derivative instruments, liabilities
(In millions)
Derivative instruments, assets
Interest rate
Derivative instruments, assets
December 31, 2015
Level 1
Level 2
Level 3
Total
$
$
$
$
$
$
— $
—
— $
— $
— $
51
8
59
1
1
$
$
$
$
— $
—
— $
— $
— $
December 31, 2014
Level 1
Level 2
Level 3
Total
— $
— $
8
8
$
$
— $
— $
51
8
59
1
1
8
8
Commodity derivatives include three-way collars, extendable three-way collars and call options. These instruments are
measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include prices, interest
rates and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and
inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2
inputs. See Note 16 for additional discussion of the types of derivative instruments we use.
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
56
$
Impairment
412
$
Fair Value
43
$
Impairment
132
$
Fair Value
5
$
Impairment
96
$
2015
2014
2013
Long-lived assets held for use that were impaired are discussed below. The fair values of each 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, unless otherwise noted. 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.
North America E&P
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 (See Note 5). The fair values were
measured using a probability weighted income approach based on both the anticipated sale price and held-for-use model.
In the third quarter of 2014, impairments of $53 million were recorded to Gulf of Mexico properties as a result of estimated
abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two fields were impaired a total of
$47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.
The Ozona development in the Gulf of Mexico ceased production in 2013 and a $21 million impairment was recorded to
write down the assets' remaining value. During 2014, we recorded additional impairments of $30 million as a result of
abandonment cost revisions.
89
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Other impairments of long-lived assets held for use in 2015, 2014 and 2013 were a result of reduced drilling expectations,
reductions of estimated reserves or decreased commodity prices.
International E&P
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.
In the fourth quarter of 2013, as a result of E.G.’s natural gas policy related to the country’s resources, we elected to cease
our efforts to develop a second LNG production train on Bioko Island and recorded a $40 million impairment of all capitalized
costs associated with engineering and feasibility studies. In addition, our share of income from EGHoldings included a $4
million impairment related to the same project, reflected in income from equity method investments in the 2013 consolidated
statement of income.
Oil Sands Mining
In the fourth quarter of 2015, impairments of $26 million were recorded related to long-lived assets used in outside
operated debottlenecking projects. Based on an evaluation by the operator, it was determined that the projects would not
continue due to a need to reduce capital intensity and improve efficiency.
Fair values – Financial instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial
paper and payables. We believe the carrying values of our receivables, commercial paper 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 investment-grade credit rating and (3) our historical incurrence of and expected future insignificance of bad debt
expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative
financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2015 and 2014.
(In millions)
Financial assets
Other noncurrent assets
Total financial assets
Financial liabilities
Other current liabilities
Long-term debt, including current portion(a)
Deferred credits and other liabilities
Total financial liabilities
(a)
Excludes capital leases.
December 31,
2015
2014
Fair
Value
Carrying
Amount
Fair
Value
Carrying
Amount
$
$
$
$
104
104
34
6,723
97
6,854
$
$
$
$
118
118
33
7,291
95
7,419
$
$
$
$
132
132
13
6,887
69
6,969
$
$
$
$
129
129
13
6,360
68
6,441
Fair values of 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.
90
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
16. Derivatives
For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for
discussion of the types of derivatives we use and the reasons for them. All of our interest rate and commodity 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)
Fair Value Hedges
Interest rate
Total Designated Hedges
Not Designated as Hedges
Commodity
Total Not Designated as Hedges
Total
(In millions)
Fair Value Hedges
Interest rate
Total Designated Hedges
$
$
$
$
$
$
$
Asset
December 31, 2015
Liability
Net Asset
Balance Sheet Location
8
8
51
51
59
$
$
$
$
$
— $
— $
1
1
1
$
$
$
8 Other noncurrent assets
8
50 Other current assets
50
58
Asset
December 31, 2014
Liability
Net Asset
Balance Sheet Location
8
8
$
$
— $
— $
8 Other noncurrent assets
8
Derivatives Designated as Fair Value Hedges
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, 2015
December 31, 2014
Aggregate
Notional Amount
(in millions)
Weighted Average,
LIBOR-Based,
Floating Rate
Aggregate
Notional Amount
(in millions)
Weighted Average,
LIBOR-Based,
Floating Rate
$
$
600
300
4.73% $
4.66% $
600
300
4.64%
4.49%
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 fair value hedges.
(In millions)
Derivative
Interest rate
Foreign currency
Hedged Item
Long-term debt
Accrued taxes
Income Statement Location
Net interest and other
Discontinued operations
Net interest and other
Discontinued operations
Gain (Loss)
Year Ended December 31,
2014
2013
2015
$
$
— $
—
— $
—
— $
(36)
— $
36
(13)
(44)
13
44
The table above reflects foreign currency forwards that hedged the current Norwegian tax liability of our Norway business,
which was reported as discontinued operations. The open positions were transferred to the purchaser of our Norway business
upon closing of the sale in the fourth quarter of 2014.
91
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
Derivatives Not Designated as Hedges
During 2015, we entered into multiple crude oil derivatives indexed to NYMEX WTI related to a portion of our forecasted
North America E&P sales through December 2016. These commodity derivatives consist of three-way collars, extendable three-
way collars and call options. 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 crude oil volumes, the floor is the minimum price we will receive,
unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference
between the floor and the sold put price. These commodity derivatives are shown in the table below:
Financial Instrument
Three-Way Collars
Weighted Average
Price
Barrels per day
Remaining Term
Ceiling
Floor
Sold put
Ceiling
Floor
Sold put
Ceiling
Floor
Sold put
Sold Call Options
$60.03
$50.20
$41.60
$71.84
$60.48
$50.00
$73.13
$65.00
$50.00
$72.39
10,000
January - March 2016 (a)
12,000
January- December 2016
2,000
January- June 2016 (b)
10,000
January- December 2016 (c)
(a)
Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted
average price as the underlying three-way collars.
(b) Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average
(c)
price as the underlying three-way collars.
Call options settle monthly.
The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated
statements of income and was a net gain of $128 million year to date December 31, 2015. There were no crude oil derivative
instruments during 2014.
On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as
it related to our Notes offering (see Note 17). Following the execution of the Treasury locks, corresponding interest rates
increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which
was recognized in net interest and other in our consolidated statements of income.
17. Debt
Short-term debt
As of December 31, 2015, we had no borrowings against our unsecured revolving credit facility (as amended, the "Credit
Facility"), as described below, or under our U.S. commercial paper program that is backed by the Credit Facility.
Revolving Credit Facility
In May 2015, we amended our $2.5 billion Credit Facility to increase by $500 million to a total of $3 billion and extended
the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally
provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment
amount by up to an additional $500 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. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain
unchanged.
92
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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, 2015, we were in
compliance with this covenant with a debt-to-capitalization ratio of 28%.
Long-term debt
The following table details our long-term debt:
(In millions)
Senior unsecured notes:
0.900% notes due 2015
6.000% notes due 2017(a)
5.900% notes due 2018(a)
7.500% notes due 2019(a)
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)
6.800% notes due 2032(a)
6.600% notes due 2037(a)
5.200% notes due 2045(a)
Capital leases:
Capital lease obligation of consolidated subsidiary due 2016 – 2049
Other obligations:
4.550% promissory note, semi-annual payments due 2015
5.125% obligation relating to revenue bonds due 2037
Total(b)
Unamortized discount
Fair value adjustments(c)
Unamortized debt issuance cost (d)
Amounts due within one year
December 31,
2015
2014
— $
682
854
228
600
1,000
32
3
70
131
900
550
750
500
9
—
1,000
7,309
(10)
17
(39)
(1)
7,276
$
1,000
682
854
228
—
1,000
32
3
70
131
—
550
750
—
9
68
1,000
6,377
(8)
22
(28)
(1,068)
5,295
$
$
Total long-term debt
(a)
(b)
These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.
In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2015 may be declared
immediately due and payable.
See Notes 15 and 16 for information on interest rate swaps.
(c)
(d) After the adoption of the debt issuance costs standard, these costs are now reflected as a direct reduction from the associated debt liability in our
consolidated balance sheets. See Note 2 for information.
Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist
of the following series:
•
•
•
$600 million of 2.70% senior notes due June 1, 2020
$900 million of 3.85% senior notes due June 1, 2025
$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We may redeem some or all
of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were
used to repay our $1 billion 0.90% senior notes that matured in November 2015, and the remainder for general corporate
purposes. As of December 31, 2015, we were in compliance with the covenants under the indenture governing the senior notes.
93
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
The following table shows future long-term debt payments:
(In millions)
2016
2017
2018
2019
2020
Thereafter
Total long-term debt, including current portion
18. Asset Retirement Obligations
$
$
1
682
854
228
600
4,944
7,309
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, including bitumen mining 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
2015
For Year Ended December 31,
2015
2014
$
$
1,958
47
(289)
105
(132)
(54)
1,635
$
$
2,096
89
(426)
104
95
—
1,958
Settled liabilities include dispositions, primarily in the Gulf of Mexico and the East Texas, North Louisiana and Wilburton,
Oklahoma as well as retirements in the Gulf of Mexico and the U.K.
Revisions of estimates were primarily due to changes in timing of activities in the U.K. and lower estimated costs across
the assets.
Held for sale is related to the Neptune field in the Gulf of Mexico.
Ending balance includes $34 million classified as short-term at December 31, 2015.
2014
Settled liabilities included the Norway and Angola dispositions.
Ending balance includes $41 million classified as short-term at December 31, 2014.
94
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)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances
Repayments
Commercial paper, net
Noncash investing activities, related to continuing operations:
Asset retirement cost increase (decrease)
Increase in capital expenditure accrual
Asset retirement obligations assumed by buyer
Year Ended December 31,
2014
2013
2015
(325) $
(171)
(279) $
(1,679)
(289)
(3,904)
— $
—
— $
(85) $
—
251
$
2,345
(2,480)
(135) $
10,870
(10,935)
(65)
$
151
335
359
290
6
92
$
$
$
$
(a)
Income taxes paid to taxing authorities includes $1,312 million and $2,270 million in 2014, and 2013 related to discontinued operations.
20. Defined Benefit Postretirement Plans and Defined Contribution Plan
We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as
international employees located in the U.K and E.G. Benefits under these plans are based on plan provisions specific to each
plan. For the U.K. pension plan, a final decision was reached with the plan trustees 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 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.
95
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(a)
Actuarial loss (gain)(b)
Foreign currency exchange rate changes
Divestiture(c)
Liability (gain)/loss due to curtailment(d)
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(c)
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
2015
2014
U.S.
518
Int’l
579
U.S.
793
Int’l
610
Other Benefits
2014
2015
U.S.
U.S.
260
279
894
29
25
(88)
26
—
—
(18)
(335)
(8)
525
$
$
$
574
8
115
—
—
(335)
(8)
354
$
(171) $
—
(8)
(163)
(171) $
$
171
(65)
$
$
$
$
$
$
$
651
14
25
1
(29)
(35)
—
(23)
—
(25)
579
622
8
36
(33)
—
—
(25)
608
29
29
—
—
29
61
4
933
31
35
—
174
—
—
—
(271)
(8)
894
$
$
$
625
59
169
—
—
(271)
(8)
574
$
(320) $
—
(11)
(309)
(320) $
649
16
27
—
46
(39)
(29)
—
—
(19)
651
$
$
$
597
59
37
(39)
(13)
—
(19)
622
$
(29) $
—
—
(29)
(29) $
279
3
11
—
(20)
—
—
2
—
(15)
260
$
$
— $
—
15
—
—
—
(15)
— $
(260) $
—
(20)
(240)
(260) $
279
3
13
(42)
42
—
—
—
—
(16)
279
—
—
16
—
—
—
(16)
—
(279)
—
(19)
(260)
(279)
$
283
10
$
91
8
$
14
(28)
34
(41)
(a)
The plan amendment in 2015 was a freeze of the final average pay used in the legacy formula of the defined benefit pension plan. Activity in 2014
represents a change in plan design related to the health care benefits provided under the postretirement plan.
(b) Activity in 2014 includes the increase in the U.S. pension and postretirement benefit obligations of $13 million and $15 million respectively, due to the
adoption of the 2014 mortality table.
Related to the sale of our Norway business in the fourth quarter of 2014.
(c)
(d) 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.
96
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.
$
$
$
$
$
4
12
—
(6)
—
—
—
10
(31)
—
—
6
(25)
(15)
Pension Benefits
Year Ended December 31,
2014
2013
2015
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
Other Benefits
Year Ended December 31,
2013
2014
2015
U.S.
U.S.
U.S.
$ 29
25
(30)
$ 14
25
(37)
$ 31
35
(34)
$ 16
27
(32)
$ 33
40
(43)
$ 17
23
(24)
$
(7)
22
(5)
119
$ 153
$
1
2
4
—
9
5
29
—
99
$ 165
1
1
—
—
$ 13
6
43
—
45
$ 124
1
4
—
—
$ 21
$
3
11
—
(4)
1
(7)
—
4
$
$
3
13
—
(6)
—
—
—
10
(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):
Actuarial loss (gain)(d)
Amortization of actuarial gain (loss)
Prior service cost (credit)
Amortization of prior service credit (cost)
$ 30
(134)
(89)
7
$ (25) $ 149
(128)
—
(5)
(2)
1
(5)
$ 33
(1)
—
(1)
$(161) $ (15) $
(88)
—
(6)
(4)
—
(1)
(21) $
(1)
—
13
42
—
(42)
6
Total recognized in other comprehensive
(income) loss
Total recognized in net periodic benefit cost and
other comprehensive (income) loss
(a)
$(186) $ (31) $ 16
$ 31
$(255) $ (20) $
(9) $
6
$ (33) $ (22) $ 181
$ 44
$(131) $
1
$
(5) $
16
(b)
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. Such
settlements occurred in one or more of our U.S. pension plans in all periods presented.
(c) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
(d) Activity in 2014 includes the impact of the sale of our Norway business in the fourth quarter of 2014.
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 2016 are $12 million and $11 million. The estimated
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 2016 is $3 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 2015, 2014 and 2013.
(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
2015
Pension Benefits
2014
2013
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
Other Benefits
2014
U.S.
2013
U.S.
2015
U.S.
4.04% 3.90% 3.71% 3.70% 4.28% 4.60% 4.36% 4.01% 4.85%
4.00% — 4.00% 3.60% 5.00% 4.90% 4.00% 4.00% 5.00%
3.79% 3.70% 3.98% 4.60% 3.79% 4.40% 3.93% 4.69% 4.06%
6.75% 5.70% 6.75% 5.70% 7.25% 4.90% —
4.00% 3.60% 5.00% 4.90% 5.00% 4.50% 4.00% 5.00% 5.00%
(a) No future benefits will be incurred for the UK plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.
—
—
97
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
2015
2014
2013
8.00%
4.50%
2024
6.88%
5.00%
2024
6.89%
5.00%
2020
Employer provided subsidy for post-65 retiree health care coverage will only increase by the consumer price index (not to
exceed 4%) each year. 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 61% equity securities and 39% fixed
income securities. The plan assets are invested in eight 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, 2015 and 2014.
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, preferred stock, and real estate investment trusts ("REIT") 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 mutual funds
are valued using a market approach. The shares or units held are traded on the public exchanges and are therefore considered
Level 1. 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
and other 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 bonds
98
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
primarily consist of securities issued by governmental agencies and municipalities. The investment in the commingled fund is
valued using the NAV of units held and is considered Level 2. The commingled fund consists of an equity and fixed income
portfolio 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.
Other – Other investments are comprised of an international insurance carrier contract and the majority of the underlying
investments consist of a mix of non-U.S. publicly traded equity securities valued at the closing price reported in an active
market and fixed income securities valued using calculated yield curves. This asset is considered Level 2. The other
investments, an unallocated annuity contract, two limited liability companies and real estate 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, 2015 and 2014.
(In millions)
Level 1
Level 2
Level 3
Total
December 31, 2015
Cash and cash equivalents
Equity securities:
Common and preferred stock
REIT and private equity
Mutual and pooled funds
Fixed income securities:
U.S. treasury notes and ETFs
Corporate and other bonds
Commingled and pooled funds
REIT and swaps
Other
Total investments, at fair value
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
$
47
$
6
$
1
$ — $ — $ — $
48
$
6
115
1
—
12
—
—
—
—
175
$
—
—
218
—
—
—
—
—
224
$
—
—
—
—
105
23
2
—
131
$
—
—
152
—
—
232
—
—
384
$
$
—
23
—
—
—
—
—
25
48
—
—
—
—
—
—
—
—
$ — $
115
24
—
12
105
23
2
25
354
$
—
—
370
—
—
232
—
—
608
(In millions)
Level 1
Level 2
Level 3
Total
December 31, 2014
Cash and cash equivalents
Equity securities:
Common and preferred stock
REIT and private equity
Mutual and pooled funds
Fixed income securities:
U.S. treasury notes and ETFs
Corporate and other bonds
Commingled and pooled funds
Other
Total investments, at fair value
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
U.S.
Int’l
$
26
$
1
$ — $ — $ — $ — $
26
$
1
230
—
—
33
—
—
—
289
$
—
—
221
—
—
—
—
222
$
—
—
—
—
190
40
—
230
$
—
—
164
—
—
236
—
400
$
$
—
25
—
—
—
—
30
55
—
—
—
—
—
—
—
$ — $
230
25
—
33
190
40
30
574
$
—
—
385
—
—
236
—
622
The activity during the year ended December 31, 2015 and 2014, for the assets using Level 3 fair value measurements was
immaterial.
99
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, 2015 and reflect expected future services, as appropriate, are to be paid in the years
indicated.
(In millions)
2016
2017
2018
2019
2020
2021 through 2025
Pension Benefits
U.S.
Int’l
Other Benefits
U.S.
$
$
61
61
59
55
53
224
$
16
17
20
21
22
125
21
21
20
20
20
89
Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $62 million
in 2016. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected
to be approximately $8 million and $21 million in 2016.
Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees.
Contributions to these plans totaled $20 million, $25 million and $27 million in 2015, 2014 and 2013.
Additional Severance Obligation – We expect to make severance payments of approximately $8 million in 2016 related to
the workforce reduction in 2015.
21. Incentive Based Compensation
Description of stock-based compensation plans – The Marathon Oil Corporation 2012 Incentive Compensation Plan (the
"2012 Plan") was approved by our stockholders in April 2012 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 2012 Plan also allows us to provide equity compensation to our non-employee
directors. No more than 50 million shares of our common stock may be issued under the 2012 Plan. For stock options and
SARs, the number of shares available for issuance under the 2012 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 2012 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 2012 Plan that are forfeited, are terminated or expire unexercised become available for
future grants. In addition, the number of shares of our common stock reserved for issuance under the 2012 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 2012 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 2012 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 2012 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, 2015, there are no SARs outstanding.
Restricted stock – We grant restricted stock under the 2012 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 – Beginning in 2013, we grant stock-based performance units to officers under the 2012
Plan. At the grant date, each unit represents the value of one share of our common stock. These units are settled in cash, and
100
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
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 under the 2012 Plan.
All non-employee directors receive annual grants of common stock units. Common shares will be issued for units granted on or
after January 1, 2012 upon completion of board service or three years from the date of grant, whichever is earlier. Any units
granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive
common shares. 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 $57 million, $70
million and $70 million in 2015, 2014 and 2013, while the total related income tax benefits were $20 million, $25 million and
$25 million in the same years. In 2015, 2014 and 2013, cash received upon exercise of stock option awards was $9 million,
$136 million and $58 million. Tax benefits realized for deductions for stock awards settled during 2014 and 2013 totaled $51
million and $36 million. There were no tax benefits realized for deductions for stock awards settled during 2015.
Stock option awards – During 2015, we granted stock option awards to officer employees. During 2014 and 2013, we
granted stock option awards to both officer and non-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 2015.
Outstanding at beginning of year
Granted
Exercised
Canceled
Outstanding at end of year
Exercisable at end of year
Expected to vest
Number
of Shares
13,427,836
724,082
(553,401)
(933,098)
12,665,419
10,654,799
1,996,175
Weighted
Average
Exercise Price
$29.68
$29.06
$16.85
$32.99
$29.97
$29.50
$32.45
2015
2014
2013
$29.06
2.9%
6.2
32%
1.7%
$6.84
$34.49
2.3%
5.9
38%
1.8%
$10.50
$33.54
2.1%
6.1
38%
1.6%
$10.25
Weighted Average
Remaining
Contractual Term
Average
Intrinsic Value
(in millions)
4 years
3 years
8 years
$
$
$
—
—
—
The intrinsic value of stock option awards exercised during 2015, 2014 and 2013 was $6 million, $83 million and $35
million.
As of December 31, 2015, unrecognized compensation cost related to stock option awards was $9 million, which is
expected to be recognized over a weighted average period of one year.
101
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 2015.
Unvested at beginning of year
Granted
Vested & Exercised
Canceled
Unvested at end of year
Awards
3,448,353
2,994,558
(1,350,344)
(1,075,223)
4,017,344
Weighted Average
Grant Date
Fair Value
$34.04
$28.90
$33.40
$32.70
$30.76
The vesting date fair value of restricted stock awards which vested during 2015, 2014 and 2013 was $26 million, $70
million and $59 million. The weighted average grant date fair value of restricted stock awards was $30.76, $34.04 and $31.80
for awards unvested at December 31, 2015, 2014 and 2013.
As of December 31, 2015 there was $86 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 2015, 2014 and 2013 we granted 382,335, 221,491 and 353,600 stock-
based performance unit awards to officers. At December 31, 2015, there were 584,566 units outstanding.
The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units
granted in 2015, 2014 and 2013 were:
Valuation date stock price
Expected annual dividend yield
Expected volatility
Risk-free interest rate
Fair value of stock-based performance units outstanding
2015
2014
2013
$12.59
1.5%
37%
1.1%
$7.08
$12.59
1.5%
46%
0.7%
$6.04
$12.98
1.5%
62%
0.1%
$0.18
Cash-based performance unit awards – Prior to 2013, cash-based performance unit awards were granted to officers that
provide a cash payment upon the achievement of certain performance goals at the end of a defined measurement period. The
performance goals are tied to our TSR as compared to TSR for a group of peer companies determined by the Compensation
Committee of the Board of Directors. The target value of each performance unit is $1, with a maximum payout of $2 per unit,
but the actual payout could be anywhere between zero and the maximum. Because performance units are to be settled in cash
at the end of the performance period, they are accounted for as liability awards.
During 2012, we granted 12.7 million performance units, all having a 36-month performance period. During the third
quarter of 2011, we granted 15 million performance units, a portion of which had a 30-month performance period and a portion
of which had an 18-month performance period to reflect the remaining periods of the original 2011 and 2010 performance unit
grants outstanding prior to the spin-off. Compensation expense associated with cash-based performance units was $5 million
and $9 million in 2014 and 2013. At December 31, 2014 all performance periods ended and no additional units have been
granted.
102
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
22. Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to income
(loss) from continuing operations in their entirety:
(In millions)
Postretirement and postemployment plans
Amortization of actuarial loss
Net settlement loss
Net curtailment gain
Other insignificant items, net of tax
Year Ended December 31,
2015
2014
Income Statement Line
$
(24) $
(119)
8
(135)
51
—
(30) General and administrative
(99) General and administrative
— General and administrative
Income (loss) from operations
Provision for income taxes
(129)
62
(1)
Total reclassifications
$
(84) $
(68)
Income (loss) from continuing
operations
23. Stockholders’ Equity
In 2014 we acquired 29 million common shares at a cost of $1 billion under our share repurchase program, initially
authorized in 2006, bringing our total repurchases to 121 million common shares at a cost of $4.7 billion. As of December 31,
2015 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.
24. 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 capital lease obligations and for operating lease obligations having noncancellable lease terms in excess of
one year are as follows:
(In millions)
2016
2017
2018
2019
2020
Later years
Sublease rentals
Total minimum lease payments
Less imputed interest costs
Present value of net minimum lease payments
Capital
Lease
Obligations
Operating
Lease
Obligations
$
$
$
$
$
1
1
1
1
1
16
—
21
(12)
9
30
26
24
24
24
30
(1)
157
Operating lease rental expense related to continuing operations was $104 million, $120 million and $105 million in 2015,
2014 and 2013.
103
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements
25. Commitments and Contingencies
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty
claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with
certainty, we believe that 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 are subject to federal, state, local and foreign laws and regulations relating to the
environment. 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, 2015 and 2014, accrued liabilities for remediation were not significant. It is not presently possible to
estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.
Guarantees – We have entered into a performance guarantee related to asset retirement obligations with aggregate
maximum potential undiscounted payments totaling $31 million as of December 31, 2015. 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, 2015 and 2014, contractual commitments to acquire property, plant and
equipment totaled $371 million and $747 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.
104
Select Quarterly Financial Data (Unaudited)
(In millions, except per share data)
Revenues
Income (loss) from continuing operations
before income taxes
Income (loss) from continuing operations
Discontinued operations (a)
Net income (loss)
Income (loss) per share:
Basic:
Continuing operations
Discontinued operations (a)
Net income (loss)
Diluted:
2015
1st Qtr. 2nd Qtr. 3rd Qtr.
$ 1,384
$ 1,490
$ 1,484
2014
4th Qtr. 1st Qtr. 2nd Qtr. 3rd Qtr.
$ 2,870
$ 1,164
$ 2,888
$ 2,690
4th Qtr.
$ 2,398
(420)
(276)
—
598
398
751
$ (276) $ (386) $ (749) $ (793) $ 1,149
(1,001)
(793)
—
(1,145)
(749)
—
(392)
(386)
—
$(0.41)
—
($0.41)
$(0.57)
—
($0.57)
$(1.11)
—
($1.11)
$(1.17)
$0.58
— $1.08
$1.66
($1.17)
511
360
180
540
$
453
304
127
431
(201)
(93)
1,019
926
$
$
$0.53
$0.27
$0.80
$0.45
$0.19
$0.64
$(0.14)
$1.51
$1.37
($0.14)
($0.57)
Continuing operations
Discontinued operations (a)
$1.51
—
$1.37
($0.57)
Net income (loss)
Dividends paid per share
$0.21
$0.21
(a) We closed the sale of our Angola assets in the first quarter of 2014 and our Norway business in the fourth quarter of 2014. The Angola assets and Norway
$0.57
— $1.08
$1.65
$0.19
($1.11)
—
($1.11)
$0.21
($0.41)
—
($0.41)
$0.21
$0.45
$0.19
$0.64
$0.21
$0.53
$0.27
$0.80
$0.19
($1.17)
$0.05
($1.17)
business are reflected as discontinued operations in 2014.
105
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
The supplementary information is disclosed by the following geographic areas: the U.S.; Canada; E.G.; Other Africa,
which primarily includes activities in Gabon, Kenya, Ethiopia and Libya; and Other International ("Other Int’l"), which
includes the U.K. and the Kurdistan Region of Iraq. We closed the sale of our Angola assets and our Norway business in 2014,
and both are shown as discontinued operations ("Disc Ops") in prior periods.
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 synthetic
crude oil is a highly technical process which is based upon several underlying assumptions that are subject to change. 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 a discussion of our reserve estimation process,
including the use of third-party audits, see Item 1. Business – Reserves.
Our December 31, 2015 proved reserves were calculated using the SEC pricing. The table below provides the 2015 SEC
pricing of the benchmark prices as well as the unweighted average for the first two months of 2016:
WTI Crude oil
Henry Hub natural gas
Brent crude oil
Natural gas liquids
$
$
$
$
SEC Pricing 2015
2-month Average 2016
34.19
2.28
50.28 $
2.59 $
54.25 $
17.32 $
34.86
12.87
When determining the December 31, 2015 proved reserves for each property, the SEC prices listed above were adjusted
using price differentials that account for property-specific quality and location differences.
Beginning in the second half of 2014, the crude oil and natural gas benchmarks began to decline and these declines
continued through 2015 and into 2016. Commodity prices are likely to remain volatile based on global supply and demand and
could decline further. Sustained reduced commodity prices could have a material effect on the quantity and future cash flows of
our proved reserves.
Estimates of future cash flows associated with proved reserves are based on actual costs of developing and producing the
reserves as of the end of the year. The decline in commodity prices prompted a concerted effort to reduce the costs of
developing and producing reserves. Therefore, the impact of sustained reduced commodity prices on future cash flows will be
partially offset by the resulting lower costs to develop and produce reserves.
A sustained period of lower commodity prices could also cause us to decrease our near term capital programs and defer
investments until prices improve. A shifting of capital expenditures into future periods beyond five years from the initial
proved reserve booking could potentially lead to a reduction in proved undeveloped reserves. See Item 1A. Risk Factors for a
further discussion of how a substantial extended decline in commodity prices could impact us.
106
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves (continued)
(mmbbl)
Crude oil and condensate
Proved developed and undeveloped reserves:
U.S.
Canada
E.G.(a)
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
Beginning of year - 2013
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 - 2013
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 - 2014
Revisions of previous estimates
Improved recovery
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2015
Proved developed reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
Proved undeveloped reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
387
33
—
12
112
(46)
(1)
497
36
2
6
153
(57)
(3)
634
(109)
1
122
(62)
(6)
580
169
241
294
327
218
256
340
253
72
(1)
—
—
1
(8)
—
64
(1)
—
—
1
(7)
—
57
2
—
—
(7)
—
52
45
37
30
25
27
27
27
27
209
12
—
—
3
(9)
—
215
(4)
—
—
—
(3)
—
208
(7)
—
—
—
—
201
168
176
175
173
41
39
33
28
24
6
—
—
—
(5)
—
25
1
—
—
7
(4)
—
29
(2)
—
—
(5)
—
22
20
19
19
16
4
6
10
6
692
50
—
12
116
(68)
(1)
801
32
2
6
161
(71)
(3)
928
(116)
1
122
(74)
(6)
855
402
473
518
541
290
328
410
314
82
19
11
—
8
(29)
—
91
10
—
—
3
(17)
(87)
—
—
—
—
—
—
—
63
77
—
—
19
14
—
—
774
69
11
12
124
(97)
(1)
892
42
2
6
164
(88)
(90)
928
(116)
1
122
(74)
(6)
855
465
550
518
541
309
342
410
314
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
107
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.
Canada
E.G.(a)
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
Beginning of year - 2013
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and
other additions
Production
End of year - 2013
Revisions of previous estimates
Improved recovery
Extensions, discoveries and
other additions
Production
End of year - 2014
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
Sales of reserves in place
End of year - 2015
Proved developed reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
Proved undeveloped reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
88
13
2
25
(9)
119
4
1
48
(11)
161
(31)
57
(14)
(1)
172
29
51
68
92
59
68
93
80
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
38
—
—
—
(4)
34
—
—
—
(4)
30
2
—
(4)
—
28
23
18
15
12
15
16
15
16
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
—
—
—
—
1
—
—
—
1
(1)
—
—
—
—
1
1
—
—
—
—
1
—
127
13
2
25
(13)
154
4
1
48
(15)
192
(30)
57
(18)
(1)
200
53
70
83
104
74
84
109
96
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
127
13
2
25
(13)
154
4
1
48
(15)
192
(30)
57
(18)
(1)
200
53
70
83
104
74
84
109
96
108
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.
Canada
E.G.(a)
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
Beginning of year - 2013
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and
other additions
Production(b)
Sales of reserves in place
End of year - 2013
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and
other additions
Production(b)
Sales of reserves in place
End of year - 2014
Revisions of previous estimates
Purchases of reserves in place
Extensions, discoveries and
other additions
Production(b)
Sales of reserves in place
End of year - 2015
Proved developed reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
Proved undeveloped reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
1,043
(4)
13
163
(114)
(76)
1,025
(24)
5
290
(113)
(39)
1,144
(191)
1
394
(128)
(69)
1,151
546
540
575
640
497
485
569
511
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,424
45
3
9
(161)
—
1,320
1
—
44
(160)
—
1,205
35
—
—
(150)
—
1,090
980
823
664
552
444
497
541
538
209
4
—
—
(8)
—
205
5
—
—
(1)
—
209
(3)
—
—
—
—
206
99
95
94
94
110
110
115
112
14
23
—
—
(9)
—
28
2
—
—
(8)
—
22
1
—
—
(8)
—
15
8
21
17
11
6
7
5
4
2,690
68
16
172
(292)
(76)
2,578
(16)
5
334
(282)
(39)
2,580
(158)
1
394
(286)
(69)
2,462
1,633
1,479
1,350
1,297
1,057
1,099
1,230
1,165
89
20
—
3
(19)
—
93
7
—
2
(13)
(89)
—
—
—
—
—
—
—
20
20
—
—
69
73
—
—
2,779
88
16
175
(311)
(76)
2,671
(9)
5
336
(295)
(128)
2,580
(158)
1
394
(286)
(69)
2,462
1,653
1,499
1,350
1,297
1,126
1,172
1,230
1,165
109
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.
Canada
E.G.(a)
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
Beginning of year - 2013
Revisions of previous estimates
Extensions, discoveries and
other additions
Production
End of year - 2013
Revisions of previous estimates
Purchases of reserves in place
Production
End of year - 2014
Revisions of previous estimates
Production
End of year - 2015
Proved developed reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
Proved undeveloped reserves:
End of year - 2013
End of year - 2014
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
653
36
6
(15)
680
(55)
38
(15)
648
67
(17)
698
653
674
644
698
6
4
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
653
36
6
(15)
680
(55)
38
(15)
648
67
(17)
698
653
674
644
698
6
4
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
653
36
6
(15)
680
(55)
38
(15)
648
67
(17)
698
653
674
644
698
6
4
110
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.
Canada
E.G.(a)
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
Beginning of year - 2013
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 - 2013
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 - 2014
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
Proved developed reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
Proved undeveloped reserves:
Beginning of year - 2013
End of year - 2013
End of year - 2014
End of year - 2015
649
45
—
16
164
(74)
(13)
787
36
2
8
250
(87)
(10)
986
(173)
1
1
245
(98)
(18)
944
289
382
458
526
360
405
528
418
653
36
—
—
6
(15)
—
680
(55)
—
38
—
(15)
—
648
67
—
—
—
(17)
—
698
653
674
644
698
—
6
4
—
347
7
—
1
2
(39)
—
318
—
—
—
8
(38)
—
288
8
—
—
1
(36)
—
261
231
193
155
129
116
125
133
132
244
12
—
—
3
(10)
—
249
(3)
—
—
—
(3)
—
243
(8)
—
—
—
—
—
235
185
192
191
189
59
57
52
46
27
11
—
—
—
(7)
31
—
—
—
7
(5)
—
33
(2)
—
—
—
(6)
—
25
22
23
22
18
5
8
11
7
1,920
111
—
17
175
(145)
(13)
2,065
(22)
2
46
265
(148)
(10)
2,198
(108)
1
1
246
(157)
(18)
2,163
1,380
1,464
1,470
1,560
540
601
728
603
97
21
11
—
9
(32)
—
106
11
—
—
3
(19)
(101)
—
—
—
—
—
—
—
—
66
80
—
—
31
26
—
—
2,017
132
11
17
184
(177)
(13)
2,171
(11)
2
46
—
268
(167)
(111)
2,198
(108)
1
1
246
(157)
(18)
2,163
1,446
1,544
1,470
1,560
571
627
728
603
(a)
(b)
Consists of estimated reserves from properties governed by production sharing contracts.
Excludes the resale of purchased natural gas used in reservoir management.
2015
Total proved reserves declined 35 mmboe, primarily due to negative revisions in the U.S. totaling 173 mmboe largely a
result of reductions to our capital development program and adherence to the SEC 5-year rule as well as routine production.
This decline was partially offset by increased reserves from the drilling programs in our U.S. unconventional shale plays
totaling 245 mmboe as well as a positive revision of 67 mmboe in OSM. The OSM revision was a consequence of technical
reevaluation and lower royalty percentages from lower realized prices. Royalties paid in Canada are on a sliding scale; as the
sales price of our synthetic crude oil increases, our royalty rate increases.
111
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
2014
U.S. proved reserves increases in 2014 from extensions, discoveries and additions of 250 mmboe were the result of
development activity in our U.S. resource plays. The sales of reserves in place related to our Norway and Angola discontinued
operations were the largest decreases in 2014 proved reserves. The negative 55 mmboe revision to Canadian synthetic crude oil
reserves primarily reflects the impact of technical and price changes on calculated royalty volumes as well as development plan
changes in the mineable areas.
2013
U.S. proved reserves increases in 2013 from extensions, discoveries and additions of 164 mmboe and revisions of previous
estimates of 45 mmboe were the result of drilling programs in our shale plays. Revisions of previous estimates increased 36
mmboe in Canada primarily due to price and cost changes.
112
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization
(In millions)
2015 Capitalized Costs:
Proved properties
Unproved properties
Total
Accumulated depreciation,
depletion and amortization:
Proved properties
Unproved properties (a)
Total
Net capitalized costs
2014 Capitalized Costs:
Proved properties
Unproved properties
Total
Accumulated depreciation,
depletion and amortization:
Proved properties
Unproved properties
Total
U.S.
Canada
E.G.
Other
Africa
Other Int'l
Total
Year Ended December 31,
$
$
$
27,816
1,625
29,441
13,656
675
14,331
15,110
28,334
1,861
30,195
13,746
189
13,935
16,260
$
$
$
$
9,538
1,389
10,927
1,420
310
1,730
9,197
9,481
1,505
10,986
1,183
1
1,184
9,802
$
$
$
$
1,955
86
2,041
1,105
—
1,105
936
1,804
64
1,868
1,010
—
1,010
858
$
$
$
$
828
465
1,293
263
107
370
923
823
460
1,283
260
—
260
1,023
$
$
$
$
5,741
242
5,983
5,195
114
5,309
674
5,707
237
5,944
5,075
9
5,084
860
$
$
$
$
45,878
3,807
49,685
21,639
1,206
22,845
26,840
46,149
4,127
50,276
21,274
199
21,473
28,803
Net capitalized costs
Includes unproved property impairments (see Note 13).
$
(a)
Costs Incurred for Property Acquisition, Exploration and Development(a)
U.S.
Canada
E.G.
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
(In millions)
December 31, 2015
Property acquisition:
Proved
Unproved
Exploration
Development
Total
December 31, 2014
Property acquisition:
Proved
Unproved
Exploration
Development
Total
December 31, 2013
Property acquisition:
$
$
$
$
4
61
959
1,477
2,501
26
202
1,140
3,532
4,900
$
$
$
$
(b)
—
—
1
—
1
—
3
4
196
203
$
$
$
$
$
$
— $
—
60
150
210
$
— $
—
35
139
174
$
9
—
4
84
97
$
$
— $
1
38
13
52
$
— $
53
119
16
188
$
— $
44
124
46
214
$
—
—
50
31
81
—
2
119
94
215
—
21
151
83
255
(c)
$
$
$
$
$
$
4
62
1,108
1,671
2,845
26
260
1,417
3,977
5,680
90
222
1,173
3,369
4,854
$
$
$
$
$
$
— $
—
—
—
— $
4
62
1,108
1,671
2,845
— $
1
6
418
425
$
26
261
1,423
4,395
6,105
— $
—
98
499
597
$
90
222
1,271
3,868
5,451
$
$
30
Proved
—
Unproved
9
Exploration
280
Development
319
Total
Includes costs incurred whether capitalized or expensed.
51
157
885
2,876
3,969
$
$
(a)
(b) Reflects reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment.
(c)
Includes negative revisions to asset retirement costs primarily due to lower estimated costs for future abandonments as well as changes in timing of these
activities in the U.K.
113
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
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
Year Ended December 31, 2014
Revenues and other income:
Sales
Transfers
Other income(a)
Total revenues and other income
Expenses:
Production costs
Exploration expenses
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, 2013
Revenues and other income:
Sales
Transfers
Other income(a)
Total revenues and other income
Expenses:
Production costs
Exploration expenses
Depreciation, depletion and
amortization(c)
Technical support and other
Total expenses
Results before income taxes
Income tax provision
Results of operations
U.S.
Canada E.G.
Other
Africa
Other
Int'l
Cont
Ops
Disc
Ops
Total
$
$ 3,374
—
230
3,604
700 $
—
—
700
40
296
—
336
$ — $
—
(109)
(109)
329
—
1
330
$ 4,443
296
122
4,861
$ — $ 4,443
296
122
4,861
—
—
—
(1,259)
(750)
(660)
(348)
(2,758)
(47)
(4,814)
(1,210)
437
(773) $
$
(266)
(2)
(1,276)
(576)
31
(545) $
$ 5,754
3
(85)
5,672
$ 1,316 $
—
—
1,316
(1,544)
(607)
(2,474)
(193)
(4,818)
854
(302)
552
$
(803)
(1)
(206)
(15)
(1,025)
291
(71)
220
$
$
(84)
(41)
(92)
(6)
(223)
113
(33)
80
43
588
—
631
(154)
(26)
(93)
(31)
(304)
327
(117)
210
(31)
(36)
(177)
(143)
(2,211)
(1,318)
— (2,211)
— (1,318)
(5)
(2)
(74)
(183)
87
(96) $
(3,284)
(60)
(6,873)
(2,012)
608
— (3,284)
(163)
(60)
(3)
—
— (6,873)
(486)
— (2,012)
(156)
608
—
86
(70) $ (1,404) $ — $ (1,404)
$
244
—
—
244
$
440
3
—
443
$ 7,797
594
(85)
8,306
189
1,848
1,832
3,869
$ 7,986
2,442
1,747
12,175
$
$
(79)
(103)
(253)
(56)
(2,833)
(793)
(181)
(5)
(3,014)
(798)
(9)
(21)
(212)
32
(32)
$ — $
(115)
(14)
(438)
5
(18)
(13) $
(2,897)
(274)
(6,797)
1,509
(540)
969
(105)
(7)
(298)
3,571
(1,496)
$ 2,075
(3,002)
(281)
(7,095)
5,080
(2,036)
$ 3,044
$ 5,059
3
(9)
5,053
$ 1,376 $
—
—
1,376
$
33
715
—
748
$ 1,106
—
—
1,106
$
687
6
(8)
685
$ 8,261
724
(17)
8,968
599
2,935
—
3,534
$ 8,860
3,659
(17)
12,502
(1,318)
(717)
(1,980)
(185)
(4,200)
853
(323)
530
$
(867)
(8)
(218)
(21)
(1,114)
262
(66)
196 $
$
(113)
(3)
(97)
(30)
(243)
505
(182)
323
$
(73)
(65)
(28)
(19)
(185)
921
(920)
1
$
(271)
(98)
(151)
(15)
(535)
150
(117)
33
(2,642)
(891)
(273)
(107)
(2,474)
(270)
(6,277)
2,691
(1,608)
$ 1,083
(345)
(38)
(763)
2,771
(1,948)
823
$
(2,915)
(998)
—
(2,819)
(308)
(7,040)
5,462
(3,556)
$ 1,906
(a)
(b)
(c)
(d)
Includes net gain (loss) on dispositions (see Note 5).
Includes unproved property impairments (see Note 13).
Includes long-lived asset impairments (see Note 13).
Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9).
114
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities
The following reconciles results of operations for oil and gas producing activities to segment income:
Year Ended December 31,
2014
2013
2015
$
(1,404) $
—
(1,404)
$
3,044
(2,075)
969
1,906
(823)
1,083
(75)
127
(57)
819
(32)
135
(487) $
73
327
58
69
—
—
1,496
$
40
340
20
10
—
—
1,493
$
(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
Long-lived asset impairments
Unrealized gain on derivatives
Alberta provincial corporate tax rate increase
Segment income
115
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
U.S. GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein
relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and
an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each
month. These and other required assumptions have not always proved accurate in the past, and other valid assumptions would
give rise to substantially different results. 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, natural gas and synthetic crude oil reserves.
(In millions)
Year Ended December 31, 2015
U.S.
Canada
E.G.
Other
Africa
Other Int'l
Total
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-
$ 31,026
(12,270)
(6,637)
(778)
$ 11,341
(6,082)
$ 31,087
(27,459)
(2,929)
—
699
(534)
$
$
$
2,671
(1,095)
(94)
(369)
1,113
(380)
$ 12,157
(901)
(689)
(9,857)
710
(441)
$
-related to continuing operations
-related to discontinued operations
Year Ended December 31, 2014
$
$
5,259
$
— $
165
$
— $
733
$
— $
269
—
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-
$ 66,307
(19,504)
(14,626)
(8,124)
$ 24,053
(12,138)
$ 55,675
(34,838)
(9,754)
(2,190)
8,893
(6,613)
$
$
$
5,027
(1,270)
(259)
(922)
2,576
(915)
$ 23,803
(803)
(680)
(21,008)
1,312
(742)
$
$
$
$
$
$
1,281
(902)
(1,537)
602
(556)
352
(a)
$ 78,222
(42,627)
(11,886)
(10,402)
$ 13,307
(7,085)
(204)
—
$
6,222
—
3,040
(1,452)
(1,669)
(9)
(90)
221
$ 153,852
(57,867)
(26,988)
(32,253)
$ 36,744
(20,187)
-related to continuing operations
-related to discontinued operations
Year Ended December 31, 2013
$ 11,915
$
$
— $
2,280
$
— $
1,661
$
— $
570
$
— $
131
—
$ 16,557
—
$
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-
$ 54,099
(16,774)
(9,685)
(7,592)
$ 20,048
(9,940)
$ 59,585
(35,954)
(9,694)
(3,098)
$ 10,839
(8,300)
$
$
5,911
(1,619)
(367)
(1,032)
2,893
(1,084)
$ 28,195
(976)
(793)
(24,982)
1,444
(828)
$
-related to continuing operations
-related to discontinued operations
Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K.
$ 10,108
$
$
— $
$
— $
$
— $
1,809
2,539
(a)
616
1,302
$
$
$
$
3,178
(1,191)
(1,302)
(643)
42
128
$ 150,968
(56,514)
(21,841)
(37,347)
$ 35,266
(20,024)
170
1,228
$ 15,242
2,530
$
116
Supplementary Information on Oil and Gas Producing Activities (Unaudited)
Changes in the Standardized Measure of Discounted Future Net Cash Flows
Year Ended December 31,
2014
2013
2015
$ (2,460)
(25,239) (b)
1,100
1,694
9,397
(7,625)
(460)
2,967
10,291
(10,335)
16,557
6,222
—
$
$
$ (5,284) $
(2,688)
3,539
4,088
(1,423)
(3,193)
(168)
3,132
3,312
1,315
15,242
$ 16,557
$
$ (2,530) $
(6,080)
(336)
3,415
3,429
898
1,330
(229)
2,657
(1,930)
3,154
12,088
15,242
399
(In millions)
Sales and transfers of oil and gas produced, net of production and support costs
Net changes in prices and production and support costs related to future production
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.
117
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the
period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the design and operation of these disclosure controls and procedures were effective as of December 31, 2015.
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 2015, there were no changes in our internal control over financial reporting that have
materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
118
PART III
Item 10. Directors, Executive Officers and Corporate Governance
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 2016 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 2015 (the
"2016 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 Business Conduct and the Code of Ethics for Senior Financial Officers are available on our website at
www.marathonoil.com.
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 2016 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 2016 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2015 with respect to shares of Marathon Oil common stock
that may be issued under our existing equity compensation plans:
• Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 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.
Plan category
Equity compensation plans approved by stockholders
Equity compensation plans not approved by stockholders
Total
(a)
Includes the following:
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
Weighted-
average
exercise price of
outstanding
options,
warrants and
rights(c)
Number of
securities
remaining available
for future issuance
under equity
compensation plans
13,715,861 (a)
12,291 (b)
13,728,152
$29.97
N/A
N/A
30,434,538 (d)
—
30,434,538
•
•
•
3,513,104 stock options outstanding under the 2012 Plan; 8,479,140 stock options outstanding under the 2007 Plan; 673,175 stock options outstanding
under the 2003 Plan;
294,800 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 2012 Plan, 2007 Plan and 2003 Plan; common stock units credited under the 2012
Plan, 2007 Plan and 2003 Plan were 97,292, 163,513 and 33,995, respectively;
755,642 restricted stock units granted to non-officers under the 2012 Plan and 2007 Plan and outstanding as of December 31, 2015.
In addition to the awards reported above 3,261,702 shares of restricted stock were issued and outstanding as of December 31, 2015, but subject to
forfeiture restrictions under the 2012 Plan.
(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 2012 Plan. No more than 14,592,300 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.
119
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 2016 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
2016" in the 2016 Proxy Statement.
120
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 – 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.
121
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 25, 2016
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, John R. Sult, 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 25, 2016 on behalf of the registrant and in the capacities indicated.
Signature
/S/ LEE M. TILLMAN
Lee M. Tillman
/S/ JOHN R. SULT
John R. Sult
/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/ PIERRE BRONDEAU
Pierre Brondeau
/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
Director
122
Exhibit Index
Exhibit Description
Articles of Incorporation and By-laws
Incorporated by Reference (File No. 001-05153,
unless otherwise indicated)
Exhibit
Filing Date
Form
Restated Certificate of Incorporation of Marathon Oil
Corporation
Marathon Oil Corporation By-laws (Amended and restated
as of September 1, 2015)
Specimen of Common Stock Certificate
Instruments Defining the Rights of Security Holders, Including Indentures
10-K
8-K
10-Q
10-K
3.1
3.1
3.3
4.2
8/8/2013
8/28/2015
2/28/2014
2/28/2014
Exhibit
Number
3
3.1
3.2
3.3
4
4.1
10
10.1
10.2
10.3†
10.4†
10.5†
10.6†
10.7†
10.8†
10.9†
10.10†
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
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
Marathon Oil Corporation 2012 Incentive Compensation
Plan
Form of Marathon Oil Corporation 2012 Incentive
Compensation Plan Non-Qualified Stock Option Award
Agreement
Form of Performance Unit Award Agreement 2014 - 2016
Performance Cycle for Section 16 Officers
Form of Performance Unit Award Agreement 2014 - 2016
Performance Cycle for Officers
Form of Initial CEO Option Grant Agreement granted under
the Marathon Oil Corporation 2012 Incentive Compensation
Plan
Form of CEO Restricted Stock Agreement granted under the
Marathon Oil Corporation 2012 Incentive Compensation
Plan (3-year prorata vesting)
Form of CEO Restricted Stock Award Agreement granted
under the Marathon Oil Corporation 2012 Incentive
Compensation Plan (3-year cliff vesting)
Form of Performance Unit Award Agreement (2013-2015
Performance Cycle) for Section 16 Officers granted under
the Marathon Oil Corporation 2012 Incentive Compensation
Plan
1
8-K
4.1
6/2/2014
10-Q
10.1
5/7/2015
DEF 14A
App. III
3/8/2012
8-K
10-Q
10-Q
10-Q
10-Q
10-Q
10-Q
10.1
10.1
10.2
10.1
8/1/2014
5/7/2014
5/7/2014
11/6/2013
10.2
11/6/2013
10.3
11/6/2013
10.1
5/10/2013
Exhibit
Number
10.11†
10.12†
10.13†
10.14†
10.15†
10.16†
10.17†
10.18†
10.19†
10.20†
10.21†
Exhibit Description
Form of Performance Unit Award Agreement (2013-2015
Performance Cycle) for Officers granted under the Marathon
Oil Corporation 2012 Incentive Compensation Plan
Form of Nonqualified Stock Option Award Agreement for
Section 16 Officers granted under the Marathon Oil
Corporation 2012 Incentive Compensation Plan (3-year
prorata vesting)
Form of Nonqualified Stock Option Award Agreement for
Officers granted under the Marathon Oil Corporation 2012
Incentive Compensation Plan (3-year prorata vesting)
Form of Restricted Stock Award Agreement for Section 16
Officers granted under the Marathon Oil Corporation 2012
Incentive Compensation Plan (3-year cliff vesting)
Form of Restricted Stock Award Agreement for Officers
granted under the Marathon Oil Corporation 2012 Incentive
Compensation Plan (3-year cliff vesting)
Form of Restricted Stock Award Agreement for Section 16
Officers granted under the Marathon Oil Corporation 2012
Incentive Compensation Plan (3-year prorata vesting)
Form of Restricted Stock Award Agreement for Officers
granted under the Marathon Oil Corporation 2012 Incentive
Compensation Plan (3-year prorata vesting)
Form of Nonqualified Stock Option Award Agreement for
non-officers granted under the Marathon Oil Corporation
2012 Incentive Compensation Plan (3-year prorata vesting)
Form of Nonqualified Stock Option Award Agreement for
non-officers in Canada granted under the Marathon Oil
Corporation 2012 Incentive Compensation Plan (3-year
prorata vesting)
Form of Restricted Stock Award Agreement for non-officers
granted under the Marathon Oil Corporation 2012 Incentive
Compensation Plan (3-year prorata vesting)
Form of Restricted Stock Unit Award Agreement for non-
officers granted under the Marathon Oil Corporation 2012
Incentive Compensation Plan (3-year prorata vesting)
10.22† Marathon Oil Corporation 2007 Incentive Compensation
Plan
10.23†
10.24†
10.25†
Form of Nonqualified Stock Option Award Agreement for
Officers granted under the Marathon Oil Corporation 2007
Incentive Compensation Plan
Form of Nonqualified Stock Option Award Agreement for
Officers granted under the Marathon Oil Corporation 2007
Incentive Compensation Plan
Form of Nonqualified Stock Option Award Agreement
granted under the Marathon Oil Corporation 2007 Incentive
Compensation Plan
Incorporated by Reference (File No. 001-05153,
unless otherwise indicated)
Exhibit
10.2
Filing Date
5/10/2013
Form
10-Q
10-K
10.5
2/22/2013
10-K
10-K
10-K
10-K
10.6
2/22/2013
10.7
2/22/2013
10.8
2/22/2013
10.9
2/22/2013
10-K
10.10
2/22/2013
10-K
10.11
2/22/2013
10-K
10.12
2/22/2013
10-K
10.13
2/22/2013
10-K
10.14
2/22/2013
10-K
10-K
10-K
10.5
10.6
2/29/2012
2/29/2012
10.5
2/28/2011
10-K
10.26
2/26/2010
10.26† Marathon Oil Corporation 2003 Incentive Compensation
10-K
10.9
2/26/2010
Plan, Effective January 1, 2003
2
Exhibit
Number
10.27†
Exhibit Description
Form of Nonqualified Stock Option Award Agreement for
Officers granted under the Marathon Oil Corporation 2003
Incentive Compensation Plan
Incorporated by Reference (File No. 001-05153,
unless otherwise indicated)
Exhibit
10.22
Filing Date
2/26/2010
Form
10-K
10.28† Marathon Oil Corporation Deferred Compensation Plan for
10-Q
10.3
5/7/2014
Non-Employee Directors (Amended and Restated as of
January 1, 2012)
10-K
10-K
10-K
10-K
10-K
10-Q
8-K
10.32
10.31
10.36
10.10
10.32
10.4
10.1
2/29/2012
2/29/2012
3/2/2015
2/28/2011
2/27/2009
11/6/2013
5/26/2011
10-K
10-K
99.1
99.1
3/2/2015
2/28/2014
10.29† Marathon Oil Company Deferred Compensation Plan
Amended and Restated Effective June 30, 2011
10.30† Marathon Oil Company Excess Benefit Plan Amended and
Restated
10.31† Marathon Oil Corporation 2011 Officer Change in Control
Severance Benefits Plan (as amended, effective November
1, 2014)
10.32† Marathon Oil Corporation Policy for Repayment of Annual
Cash Bonus Amounts
10.33† Marathon Oil Executive Tax, Estate, and Financial Planning
Program, Amended and Restated, Effective January 1, 2009
10.34† Marathon Oil Corporation Bonus Agreement Upon
10.35
12.1*
21.1*
23.1*
23.2*
23.3*
23.4*
31.1*
31.2*
32.1*
32.2*
99.1*
99.2
99.3
Commencement of Employment for Lee M. Tillman
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 GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists
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 Executive Vice President and 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 Executive Vice President and Chief
Financial Officer pursuant to 18 U.S.C. Section 1350
Report of GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists for 2015
Report of GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists for 2014
Report of GLJ Petroleum Consultants LTD., independent
petroleum engineers and geologists for 2013
3
Incorporated by Reference (File No. 001-05153,
unless otherwise indicated)
Exhibit
Filing Date
Form
10-K
10-K
10-K
10-K
99.4
3/2/2015
99.4
2/28/2014
99.7
3/2/2015
99.7
2/28/2014
Exhibit
Number
99.4*
99.5
99.6
99.7*
99.8
99.9
Exhibit Description
Summary report of audits performed by Netherland, Sewell
& Associates, Inc., independent petroleum engineers and
geologists for 2014
Summary report of audits performed by Netherland, Sewell
& Associates, Inc., independent petroleum engineers and
geologists for 2013
Summary report of audits performed by Netherland, Sewell
& Associates, Inc., independent petroleum engineers and
geologists for 2012
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2014
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2013
Summary report of audits performed by Ryder Scott
Company, L.P., independent petroleum engineers and
geologists for 2012
101.INS* 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.
Furnished, not filed.
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
Chris C. Phillips, Director, Investor Relations
+1 713-296-3213
Zach B. Dailey, Director, Investor Relations
+1 713-296-4140
Notice of Annual Meeting
The 2016 Annual Meeting of Stockholders will be held in Houston,
Texas, on May 25, 2016.
Independent Accountants
PricewaterhouseCoopers LLP
1201 Louisiana, Suite 2900
Houston, TX 77002-5678
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 2014 Annual Report
(the “2014 Peer Group”), and the new Peer Group Index that
replaces it (the “2015 Peer Group”). The 2015 Peer Group Index
reflects the removal of Talisman Energy, Inc. due to its acquisition
in 2015, and the addition of ConocoPhillips and Pioneer Natural
Resources Company. 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 2015 Peer
Group Index is comprised of Anadarko Petroleum Corp., Apache
Corp., Chesapeake Energy Corp., ConocoPhillips, Devon Energy
Corp., Encana Corp., EOG Resources Inc., Hess Corp., Murphy Oil
Corp., Noble Energy Inc., Occidental Petroleum Corp., and Pioneer
Natural Resources Company.
Comparison of Cumulative Total Return on $100
Invested in Marathon Oil Common Stock on December 31, 2010
vs.
*S&P 500 and Peer Group Index
250
200
150
100
50
0
Dec 10
Dec 11
Dec 12
Dec 13
Dec 14
Dec 15
MRO
S&P 500
2014 Peer Group Index
2015 Peer Group Index
*Total return assumes reinvestment of dividends
Forward-Looking Statements
The 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 operational, financial and growth
strategies, including planned projects, drilling plans, balance sheet protection, workforce reductions and expected savings, cost
reductions, the dividend reduction, non-core asset sales and targets, and enhanced operational activity; the Company’s ability
to successfully effect those strategies and the expected timing and results thereof; reserve estimates; production guidance; the
Company’s financial and operational outlook, and ability to fulfill that outlook; expectations regarding future economic and market
conditions and their effects on the Company; the Company’s financial position, liquidity and capital resources; and the Company’s
2016 capital program and the planned allocation thereof.
While the Company believes that the assumptions concerning future events are reasonable, a number of factors could cause actual
results to differ materially from those projected, including, but not limited to: conditions in the oil and gas industry, including
supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or
economic conditions in key operating markets, including international markets; capital available for exploration and development;
well production timing; availability of drilling rigs, materials and labor; difficulty in obtaining necessary approvals and permits; non-
performance by third parties of contractual obligations; unforeseen hazards such as weather conditions, acts of war or terrorism
and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental 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 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public
filings and press releases, available at www.marathonoil.com. The Company undertakes no obligation to revise or update any
forward-looking statements as a result of new information, future events or otherwise.