Document

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, 2016
Commission file number 1-5153
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Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware
 
25-0996816
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, 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
 
Name of each exchange on which registered
Common Stock, par value $1.00
 
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, 2016: $12,696 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 847,201,196 shares of Marathon Oil Corporation Common Stock outstanding as of February 15, 2017.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2017 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
 


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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 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.
E&P - Exploration and production.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.
FASB – Financial Accounting Standards Board.
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.

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mmbtu – Million British thermal units.
mmcfd – Million cubic feet per day.
mmta – Million metric tonnes per annum.
MPC Marathon Petroleum Corporation – the separate independent company, which owns and operates the downstream business.
mt – metric tonnes
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. Undrilled locations can be classified as having proved undeveloped reserves if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic 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.

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Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures and 4-D factors in changes that occurred over time).
STACK – Sooner Trend, Anadarko (basin), Canadian (and) Kingfisher (counties).
TD - Total depth or the bottom of a drilled hole.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
U.K. – United Kingdom.
U.S. – United States of America.
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 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 interests or other interests.
WTI – West Texas Intermediate crude oil, an oil index benchmark price as quoted by NYMEX.


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Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation: our operational, financial and growth strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, non-core asset sales, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2017 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 supply/demand levels for crude oil and condensate, NGLs, natural gas and synthetic crude oil and the resulting impact on price;
changes in expected reserve or production levels;
changes in political or economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
risks relating to our hedging activities;
capital available for exploration and development;
drilling and operating risks;
well production timing;
availability of drilling rigs, materials and labor, including the costs associated therewith;
difficulty in obtaining necessary approvals and permits;
non-performance by third parties of their contractual obligations;
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks;
changes in safety, health, environmental, tax and other regulations;
other geological, operating and economic considerations; and
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.




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PART I
Item 1. Business
General
Marathon Oil Corporation (NYSE: MRO) is an independent exploration and production company based in Houston, Texas, focused on U.S. unconventional resource plays with operations in North America, Europe and Africa. Our corporate headquarters is located at 5555 San Felipe Street, Houston, Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers. The three segments are:
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.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, for a more detailed discussion of our operating results, cash flows and outlook, including our 2017 Capital Program.
The map below shows the locations of our worldwide operations.
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Segment and Geographic Information
For reportable 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 production activities in the U.S. Our primary focus in the North America E&P segment is concentrated within our three quality unconventional resource plays.
North America E&P-- Unconventional Resource Plays
Oklahoma Resource Basins – We hold approximately 365,000 net surface acres and includes 61,000 net acres added in the PayRock acquisition in the STACK Meramec play during 2016. In the SCOOP and STACK areas we hold net acres with rights to the Woodford, Springer, Meramec, Osage, Oswego, Granite Wash and other Pennsylvanian and Mississippian plays. Our primary 2017 focus will be in the Meramec play in the STACK and the Woodford and Springer plays in the SCOOP.  
Eagle Ford - We hold approximately 145,000 net acres in south Texas where we have been operating since 2011. We operate more than 1,365 gross (962 net) producing wells, 32 central gathering and treating facilities and approximately 865 miles of gathering pipeline in the Eagle Ford.  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.
Approximately 95% of the crude oil and condensate production is transported by pipeline with connections to multiple sales points.  The ability to transport more barrels by pipeline enables us to improve/optimize price realizations, reduce costs, improve reliability and lessen our environmental footprint.
Bakken – We hold approximately 270,000 net acres in North Dakota and eastern Montana, where we have been operating since 2006. Our large scale water gathering system is handling nearly 70% of our produced water.  We are currently transporting about 75% of our oil production on pipeline.  In an effort to optimize price realizations, we sell our production in local North Dakota markets and to select purchasers who may elect to transport outside of the state.
Other North America
Our remaining properties in North America primarily consist of a number of outside operated assets in the Gulf of Mexico, the largest of which is the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). The Gunflint field, in which we hold an 18% non-operated working interest, achieved first oil in the third quarter of 2016.
In 2016, we continued our progress on portfolio management, with approximately $1.3 billion of non-core assets sales, which mainly included Wyoming and West Texas properties. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
International E&P Segment
We are engaged in a range of activities, including oil and gas exploration, development and production across our international locations 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.
Africa
Equatorial GuineaProduction – 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 2016.
Equatorial GuineaGas Processing – We own a 52% interest in Alba Plant LLC, an equity method investee, which operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas, under a long-term contract at a fixed price per btu, is processed by the LPG plant. The LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations.
We also own 60% of EGHoldings and 45% of AMPCO, both of which are accounted for as equity method investments. EGHoldings operates a 3.7 mmta LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to further monetize natural gas production from the Alba field. AMPCO had gross sales totaling 1,100 mt in 2016. Methanol production is sold to customers in Europe and the U.S.
The LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement. Under the agreement, which runs through 2023, the purchaser takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index. Gross sales of LNG from this production facility totaled 3.6 mmta in 2016.

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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. Civil and political unrest has interrupted our production operations in recent years.  During 2016, Force Majeure was lifted in September, production commenced shortly thereafter and liftings resumed in December. 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 operated 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, a 39% working interest in the East Brae field, and a 28% working interest in the nearby Braemar field.
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 pipeline system, which 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 2016, we relinquished to the Kurdistan Regional Government our 45% operated working interest in the Harir block located northeast of Erbil.  We have non-operated interests in two blocks located north-northwest of Erbil: Atrush with a 15% working interest and Sarsang with a 20% working interest. 
International E&P Exploration
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 unitization with the Alba field. Negotiations have been substantially completed and we are awaiting approval from the host government.
Gabon – Exploration – We hold a 21.25% non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, and a 100% participating interest and operatorship in the Tchicuate block where we have an exploration and production sharing agreement.
In 2015, we entered into agreements to sell our East Africa exploration acreage in Ethiopia and Kenya. This transaction closed during the first quarter of 2016. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.
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. 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.
As of December 31, 2016, we own or have rights to participate in developed and undeveloped surface mineable leases totaling approximately 155,000 gross (31,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta.
Reserves
Proved 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. Approximately 79% of our proved reserves are located in OECD countries.

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The following tables set forth estimated quantities of our total proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves based upon an SEC pricing for period ended December 31, 2016.
 
North America
 
Africa
 
 
 
 
December 31, 2016
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Total
Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
238

 

 
238

 
45

 
172

 
217

 
13

 
468

Natural gas liquids (mmbbl)
78

 

 
78

 
24

 

 
24

 

 
102

Natural gas (bcf)
648

 

 
648

 
943

 
95

 
1,038

 
5

 
1,691

Synthetic crude oil (mmbbl)

 
692

 
692

 

 

 

 

 
692

Total proved developed reserves  (mmboe)
424

 
692

 
1,116

 
226

 
188

 
414

 
14

 
1,544

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
325

 

 
325

 

 

 

 
9

 
334

Natural gas liquids (mmbbl)
92

 

 
92

 

 

 

 

 
92

Natural gas (bcf)
640

 

 
640

 

 
110

 
110

 
5

 
755

Synthetic crude oil (mmbbl)

 

 

 

 

 

 

 

Total proved undeveloped reserves  (mmboe)
524

 

 
524

 

 
18

 
18

 
10

 
552

Total Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
563

 

 
563

 
45

 
172

 
217

 
22

 
802

Natural gas liquids (mmbbl)
170

 

 
170

 
24

 

 
24

 

 
194

Natural gas (bcf)
1,288

 

 
1,288

 
943

 
205

 
1,148

 
10

 
2,446

Synthetic crude oil (mmbbl)

 
692

 
692

 

 

 

 

 
692

Total proved reserves (mmboe)
948

 
692

 
1,640

 
226

 
206

 
432

 
24

 
2,096

As of December 31, 2016, we had total estimated proved reserves of 802 mmbbl of crude oil and condensate, 194 mmbbl of NGLs, 2,446 bcf of natural gas, and 692 mmbbl of synthetic crude oil. Combined, total estimated proved reserves are 2,096 mmboe, of which liquids represents 81 percent. As of December 31, 2016, we had estimated proved developed reserves totaled 1,544 mmboe or 74% and estimated proved undeveloped reserves totaling 552 mmboe or 26% of our total proved reserves. For additional detail on reserves, see Item 8. Financial Statements and Supplementary Data - Supplementary Information on Oil and gas Producing Activities.
Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGLs, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group ("CRG"), which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGLs, natural gas and synthetic crude oil reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are petro-technical professionals located throughout our organization who meet the qualifications we have established for employees engaged in estimating reserves and resources. QREs have the education, experience, and training necessary to estimate reserves and resources in a manner consistent with all external reserve estimation regulations and internal resource estimation directives and practices. QREs generally hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed our QRE training course. All reserves changes (including proved) must be approved by the CRG. Additionally, any change to proved reserve estimates in excess of 5 mmboe on a total field basis, within a single month, must be approved by the Director of Corporate Reserves.
The Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of New Mexico. In his 30 years with Marathon Oil, he has held numerous engineering and management positions, including more recently managing reservoir engineering and geoscience for our Eagle Ford development in South Texas. He is a 25 year member of the Society of Petroleum Engineers ("SPE").
Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The

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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.
Estimates of synthetic crude oil reserves were prepared by GLJ Petroleum Consultants of Calgary, Alberta, Canada, third-party consultants during 2015 and 2014. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The individual responsible, during 2015 and 2014, for the estimates of our synthetic crude oil reserves had 15 years of experience in petroleum engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional Engineer in the Province of Alberta.
Audits of Estimates
We engage third-party consultants to provide, at a minimum, independent estimates for fields that comprise 80% of our total proved reserves over a rolling four-year period. We exceeded this percentage for the four-year period ended December 31, 2016, with 84% of our total proved reserves independently audited. An audit tolerance at a field level of +/- 10%, to our internal estimates, has been established. Should the third-party consultants’ initial analysis fall outside our tolerance band, both parties will re-examine the information provided, request additional data and refine their analysis, if appropriate. In the very limited instances where differences outside the 10% tolerance cannot be resolved by year end, a plan to resolve the difference is developed and executive management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2016, 2015 or 2014.
During 2016, 2015 and 2014, Netherland, Sewell & Associates, Inc. prepared a reserves certification for the last three reporting periods for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI. NSAI’s technical team members meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The senior technical advisor has over 12 years of practical experience in petroleum engineering and the estimation and evaluation of reserves and is a registered Professional Engineer in the State of Texas. The second team member has over 10 years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the State of Texas.
Ryder Scott Company also performed audits of the prior years' reserves of several of our fields in 2016, 2015 and 2014. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 34 years of industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a 25 year member of SPE and is a registered Professional Engineer in the State of Texas.


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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, service wells and drilling wells as of December 31 for the years presented.
 
Productive Wells(a)
 
 
 
 
 
 
 
 
 
Oil
 
Natural Gas
 
Service Wells  
 
Drilling Wells
  
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. (b)
4,533

 
1,650

 
1,830

 
708

 
821

 
85

 
42

 
10

E.G.

 

 
17

 
11

 
2

 
1

 

 

Other Africa
1,071

 
175

 
7

 
1

 
94

 
16

 

 

Total Africa
1,071

 
175

 
24

 
12

 
96

 
17

 

 

Other International
62

 
23

 
35

 
14

 
23

 
8

 

 

Total
5,666

 
1,848

 
1,889

 
734

 
940

 
110

 
42

 
10

2015

 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
7,198

 
2,878

 
1,796

 
750

 
2,727

 
747

 
 
 
 
E.G.

 

 
17

 
11

 
2

 
1

 
 
 
 
Other Africa
1,071

 
175

 
7

 
1

 
94

 
16

 
 
 
 
Total Africa
1,071

 
175

 
24

 
12

 
96

 
17

 
 
 
 
Other International
59

 
21

 
39

 
16

 
24

 
8

 
 
 
 
Total
8,328

 
3,074

 
1,859

 
778

 
2,847

 
772

 
 
 
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
7,058

 
2,919

 
2,246

 
1,023

 
2,638

 
760

 
 
 
 
E.G.

 

 
16

 
11

 
2

 
1

 
 
 
 
Other Africa
1,071

 
175

 
7

 
1

 
94

 
16

 
 
 
 
Total Africa
1,071

 
175

 
23

 
12

 
96

 
17

 
 
 
 
Other International
55

 
20

 
39

 
16

 
24

 
8

 
 
 
 
Total
8,184

 
3,114

 
2,308

 
1,051

 
2,758

 
785

 
 
 
 
(a) 
Of the gross productive wells, wells with multiple completions operated by us totaled 8, 12 and 31 as of December 31, 2016, 2015 and 2014. Information on wells with multiple completions operated by others is unavailable to us.
(b) 
Reduction in December 31, 2016 gross and net productive wells and service wells is primarily due to the dispositions of our West Texas and Wyoming assets in 2016. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.




10


Drilling Activity
For our North America E&P and International E&P segments, the table below sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed as of December 31 for the years represented.
 
Development
 
Exploratory
 
 
  
Oil
 
Natural
Gas
 
Dry
 
Total
 
Oil
 
Natural
Gas
 
Dry
 
Total
 
Total
2016
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
64

 
12

 

 
76

 
70

 
27

 

 
97

 
173

E.G.

 

 

 

 

 

 

 

 

Other Africa

 

 

 

 

 

 

 

 

Total Africa

 

 

 

 

 

 

 

 

Other International

 

 

 

 

 

 

 

 

Total
64

 
12

 

 
76

 
70

 
27

 

 
97

 
173

2015
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
135

 
36

 
11

 
182

 
49

 
48

 
1

 
98

 
280

E.G.

 
1

 

 
1

 

 

 
1

 
1

 
2

Other Africa

 

 

 

 

 

 

 

 

Total Africa

 
1

 

 
1

 

 

 
1

 
1

 
2

Other International
1

 

 

 
1

 

 

 

 

 
1

Total
136

 
37

 
11

 
184

 
49

 
48

 
2

 
99

 
283

2014
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
253

 
43

 
1

 
297

 
49

 
19

 
4

 
72

 
369

E.G.

 

 

 

 

 

 
1

 
1

 
1

Other Africa
1

 

 

 
1

 

 

 

 

 
1

Total Africa
1

 

 

 
1

 

 

 
1

 
1

 
2

Other International
1

 

 

 
1

 

 

 

 

 
1

Total
255

 
43

 
1

 
299

 
49

 
19

 
5

 
73

 
372

Acreage
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, 2016.
 
Developed
 
Undeveloped
 
Developed and
Undeveloped
(In thousands)
Gross    
 
Net
 
Gross    
 
Net
 
Gross    
 
Net
U.S.
1,399

 
1,053

 
413

 
386

 
1,812

 
1,439

Canada

 

 
142

 
54

 
142

 
54

Total North America
1,399

 
1,053

 
555

 
440

 
1,954

 
1,493

E.G.
45

 
29

 
92

 
73

 
137

 
102

Other Africa
12,909

 
2,108

 
2,519

 
753

 
15,428

 
2,861

Total Africa
12,954

 
2,137

 
2,611

 
826

 
15,565

 
2,963

Other International
86

 
31

 
171

 
32

 
257

 
63

Total
14,439

 
3,221

 
3,337

 
1,298

 
17,776

 
4,519


11


In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. If production is not established or we take no other action to extend the terms of the leases, licenses or concessions, additional undeveloped acreage will expire in future years. We plan to continue the terms of certain of these licenses and concession areas or retain leases through operational or administrative actions.
Net Production
 
North America
 
Africa
 

 
 
 
 
  
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Disc Ops
 

Total
Year Ended December 31,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (mbbld)(a)
131

 

 
131

 
20

 
3

 
23

 
12

 

 
166

Natural gas liquids (mbbld)
40

 

 
40

 
11

 

 
11

 

 

 
51

Natural gas (mmcfd)(b)
314

 

 
314

 
425

 

 
425

 
28

 

 
767

Synthetic crude oil (mbbld)(c)

 
48

 
48

 

 

 

 

 

 
48

Total production (mboed)
223

 
48

 
271

 
102

 
3

 
105

 
17

 

 
393

2015
 
 
 

 
 
 
 
 

 
 
 
 
 

Crude and condensate (mbbld)(a)
171

 

 
171

 
19

 

 
19

 
14

 

 
204

Natural gas liquids (mbbld)
39

 

 
39

 
10

 

 
10

 

 

 
49

Natural gas (mmcfd)(b)
351

 

 
351

 
410

 

 
410

 
21

 

 
782

Synthetic crude oil (mbbld)(c)

 
45

 
45

 

 

 

 

 

 
45

Total production (mboed)
269

 
45

 
314

 
97

 

 
97

 
18

 

 
429

2014
 
 
 

 
 
 
 
 

 
 
 
 
 

Crude and condensate (mbbld)(a)
157

 

 
157

 
21

 
7

 
28

 
11

 
48

 
244

Natural gas liquids (mbbld)
29

 

 
29

 
10

 

 
10

 

 

 
39

Natural gas (mmcfd)(b)
310

 

 
310

 
439

 
1

 
440

 
21

 
37

 
808

Synthetic crude oil (mbbld)(c)

 
41

 
41

 

 

 

 

 

 
41

Total production (mboed)
238

 
41

 
279

 
104

 
7

 
111

 
15

 
54

 
459

(a) 
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) 
Excludes volumes acquired from third parties for injection and subsequent resale.
(c) 
Upgraded bitumen excluding blendstocks.

Average Production Cost per Unit (a) 
 
North America
 
Africa
 
 
 
 
 
 
(Dollars per boe)
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Disc Ops
 

Total
2016
$
9.84

 
$
29.36

 
$
13.35

 
$
2.17

 
N.M.
 
$
2.17

 
$
23.13

 
$

 
$
11.02

2015
10.65

 
38.42

 
14.69

 
2.37

 
N.M.
 
2.37

 
27.23

 

 
12.62

2014
13.34

 
46.63

 
18.73

 
4.03

 
N.M.
 
4.03

 
47.06

 
8.92

 
15.37

(a) 
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.
N.M. Not meaningful information due to limited sales.

12



Average Sales Price per Unit(a) 
 
North America
 
Africa
 

 
 
 
 
(Dollars per unit)
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Disc Ops
 

Total
2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
38.57

 
$

 
$
38.57

 
$
38.85

 
$
57.69

 
$
40.95

 
$
43.21

 
$

 
$
39.23

Natural gas liquids (bbl)
13.15

 

 
13.15

 
1.00

(b) 

 
1.00

 
26.41

 

 
10.68

Natural gas (mcf)
2.38

 

 
2.38

 
0.24

(b) 

 
0.24

 
4.80

 

 
1.26

Synthetic crude oil (bbl)

 
37.57

 
37.57

 

 

 

 

 

 
37.57

2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
43.50

 
$

 
$
43.50

 
$
42.83

 
$

 
$
42.83

 
$
53.91

 
$

 
$
44.14

Natural gas liquids (bbl)
13.37

 

 
13.37

 
1.00

(b) 

 
1.00

 
32.53

 

 
11.16

Natural gas (mcf)
2.66

 

 
2.66

 
0.24

(b) 

 
0.24

 
6.85

 

 
1.50

Synthetic crude oil (bbl)

 
40.13

 
40.13

 

 

 

 

 

 
40.13

2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
85.25

 
$

 
$
85.25

 
$
81.01

 
$
94.70

 
$
84.48

 
$
94.31

 
$
109.80

 
$
90.37

Natural gas liquids (bbl)
33.42

 

 
33.42

 
1.00

(b) 

 
1.00

 
67.73

 

 
25.25

Natural gas (mcf)
4.57

 

 
4.57

 
0.24

(b) 
3.11

 
0.25

 
8.27

 
9.94

 
2.55

Synthetic crude oil (bbl)

 
83.35

 
83.35

 

 

 

 

 

 
83.35

(a) 
Excludes gains or losses on commodity derivative instruments.
(b) 
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.

Marketing
Our reportable operating segments include activities related to the marketing and transportation of substantially all of our crude oil and condensate, NGLs, natural gas and synthetic crude oil. 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.
Delivery Commitments
We have committed to deliver quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil to customers under a variety of contracts. As of December 31, 2016, the contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to the following sales commitments:
 
 
2017
 
2018
 
2019
 
Thereafter
 
Commitment Period Through
Eagle Ford
 
 
 
 
 
 
 
 
 
 
Crude and condensate (mbbld)
 
105

 
80

 
66

 
51
 
2020
Natural gas (mmcfd)
 
210

 
168

 
168

 
46 - 168
 
2022
Bakken
 
 
 
 
 
 
 
 
 
 
Crude and condensate (mbbld)
 
5

 
10

 
10

 
5-10
 
2027
OSM
 
 
 
 
 
 
 
 
 
 
Synthetic crude oil (mbbld)
 
10

 

 

 
 
 
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.

13


Competition
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.
Environmental, Health and Safety Matters
The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety matters. Our Corporate Health, Environment, Safety and Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.
Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and safety at the national, state and local levels. These laws and their implementing regulations and other similar state and local laws and rules can impose certain operational controls for minimization of pollution, recordkeeping, monitoring and reporting requirements or other operational or siting constraints on our business, result in costs to remediate releases of regulated substances, including crude oil, into the environment, or require costs to remediate sites to which we sent regulated substances for disposal. In some cases, these laws can impose strict liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others (such as prior owners or operators of our assets) or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.
New laws have been enacted and regulations are being adopted by various regulatory agencies on a continuing basis and the costs of compliance with these new laws and regulations can only be broadly appraised until their implementation becomes more defined.
For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.
Air and Climate Change
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 June 2016, the EPA published a suite of final 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. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities. We are currently evaluating the impact of these rules on our operations. If we are unable to comply with the terms of these regulations, we could be required to forego construction or implement modifications to 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.

14


In 2010, the EPA promulgated rules that require us to monitor and submit an annual report on our greenhouse gas emissions. In October 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gas monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Further, state, national and international requirements to reduce greenhouse emissions are being proposed and in some cases promulgated (see discussion above regarding 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 November 2016, the Bureau of Land Management (“BLM”) issued a final rule to further restrict venting and/or flaring of gas from facilities subject to BLM jurisdiction, and to modify certain royalty requirements.  These regulations are currently subject to a challenge under the Congressional Review Act, which if successful, would result in complete withdrawal of these requirements. If not withdrawn, this rule is expected to result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.  If we are unable to comply with the terms of these regulations, we could be required to forego certain operations. These regulations may also result in administrative, civil and/or criminal penalties for non-compliance.
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.
For additional information, see Item 1A. Risk Factors.
Transportation
A number of state and federal rules apply to the transportation of liquid hydrocarbons. In 2015, 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. Similarly, in August 2016, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), a sub-agency of DOT, published a final rule setting additional safety requirements and retrofits for rail cars. PHMSA is also considering revising its regulations to require particular methods for conducting vapor pressure testing and sampling of unrefined petroleum-based products for transportation. 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, PHMSA has proposed or announced the intention to propose various rules related to pipeline transportation of natural gas and/or liquid hydrocarbons. For example, in October 2015, PHMSA published a notice of proposed rulemaking amending its hazardous liquid pipeline safety regulations and in April 2016, published a notice of proposed rulemaking addressing natural gas transmission and gathering lines. 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.

15


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 2016, sales to Irving Oil and Valero Marketing and Supply and each of their respective affiliates accounted for approximately 17% and 10% of our total revenues. 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.
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 2,117 active, full-time employees as of December 31, 2016.
Executive Officers of the Registrant
The executive officers of Marathon Oil and their ages as of February 1, 2017, are as follows:
Lee M. Tillman
 
55
 
President and Chief Executive Officer
Sylvia J. Kerrigan
 
51
 
Executive Vice President, General Counsel and Secretary
T. Mitch Little
 
53
 
Executive Vice President—Operations
Patrick J. Wagner
 
52
 
Interim Chief Financial Officer and Vice President-Corporate Development and Strategy
Catherine L. Krajicek
 
55
 
Vice President—Conventional
Gary E. Wilson
 
55
 
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.
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.
Mr. Little was appointed executive vice president of operations in August 2016 after having served as vice president, conventional since December 2015, vice president international and offshore exploration and production operations since September 2013, and as vice president, international production operations since September 2012. Prior to that, Mr. Little was resident manager of our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little joined Marathon Oil in 1986 and has since held a number of engineering and management positions of increasing responsibility.
Mr. Wagner was appointed vice president—corporate development in April 2014, and since August 2016 has been serving as interim chief financial officer. 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, which he joined in early 2012 as vice president, exploitation. Prior to that, Mr. Wagner was managing director in Houston for Scotia Waterous, the oil and gas arm of Scotiabank (an international banking services provider), from 2010 to 2012. Before joining Scotia, Mr. Wagner was vice president, Gulf of Mexico, for Devon Energy Corp. (an oil and natural gas producer), having joined Devon in 2003 as manager, international exploitation.
Ms. Krajicek was appointed vice president—conventional assets in August 2016 after having served as vice president of technology and innovation since December 2015. Prior to that, Ms. Krajicek served as vice president, health, environment, safety and security from January 2015 through December 2015. Ms. Krajicek joined Marathon Oil in 2007 and has since held a number of positions of increasing responsibility. Prior to joining the Company, Ms. Krajicek spent 22 years with Conoco and then ConocoPhillips (a multinational energy corporation), where she held a variety of reservoir engineering and asset management and development management positions for upstream and mid-stream businesses under development, both in the U.S. and internationally.
Mr. Wilson was appointed vice president, controller and chief accounting officer in October 2014. Prior to joining Marathon Oil, he served in various finance and accounting positions of increasing responsibility at Noble Energy, Inc. (a global

16


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.

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Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under "Disclosures Regarding Forward-Looking Statements" and other information included and incorporated by reference into this Annual Report on Form 10-K.
The substantial decline in crude oil and condensate, NGLs, natural gas and synthetic crude oil prices since 2014 has reduced our operating results and cash flows and, regardless of the recent increase in prices, could still 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. Although, prices for WTI and Brent crude oil, Henry Hub natural gas and natural gas liquids have increased in the last several months, prices are still significantly below their highs from 2014. 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 and certain non-OPEC members, such as Russia, to agree to and maintain production controls;
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
political instability or armed conflict in oil and natural gas producing regions;
changes in weather patterns and climate;
natural disasters such as hurricanes and tornadoes;
the price and availability of alternative and competing forms of energy;
the effect of conservation efforts;
epidemics or pandemics;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxes; and
general economic conditions worldwide.
The long-term effects of these and other factors on the prices of crude oil and condensate, NGLs, natural gas and synthetic crude oil are uncertain. Historical declines in commodity prices have adversely affected our business by:
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.
Future decreases in prices could have similar adverse effects on our business.

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If crude oil and condensate, NGLs, natural gas and synthetic crude oil prices remain substantially below their 2014 highs or fall below current levels, it could adversely affect the abilities of our counterparties to perform their obligations to us, including abandonment obligations, which could negatively impact our financial results.
We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, oil sands mining or transportation of crude oil and condensate, NGLs, natural gas and synthetic crude oil, 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.
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 crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves were prepared, in accordance with SEC regulations, by our in-house teams of reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group. Prior to 2016, 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, 2016, 2015 and 2014, as well as other conditions in existence at those dates. The table below provides the 2016 SEC pricing for certain benchmark prices:
 
SEC Pricing 2016
WTI Crude oil (per bbl)
$
42.75

Henry Hub natural gas (per mmbtu)
$
2.49

Brent crude oil (per bbl)
$
43.53

Mont Belvieu NGLs (per bbl)
$
15.89

If commodity prices were to significantly drop below average prices used to estimate 2016 proved reserves (see table above), we would expect price related reserve revisions that could have a material impact on proved reserve volumes and the present value of our proved reserves. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserves or resource category. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and condensate, NGLs, 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:
location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
historical production from the area, compared with production from other analogous producing areas;
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 impacts of regulation by governmental agencies;
assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
industry economic conditions, levels of cash flows from operations and other operating considerations.
As a result, different petroleum engineers and geoscientists, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ materially from the estimated amounts:
the amount and timing of production;

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the revenues and costs associated with that production; and
the amount and timing of future development expenditures.
If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and condensate, NGLs, natural gas and synthetic crude oil production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.
The rate of production from crude oil and condensate, NGLs, natural gas and synthetic crude oil 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:
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.
Future exploration and drilling results are uncertain and involve substantial costs.
Drilling for crude oil and condensate, NGLs and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
inflation in exploration and drilling costs;
fires, explosions, blowouts or surface cratering;
lack of access to pipelines or other transportation methods; and
shortages or delays in the availability of services or delivery of equipment.
If 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:
denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
increased costs or operational delays resulting from shortages of water;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;

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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
Any one or more of these factors could have a significant impact on our capital projects.
Our offshore operations involve special risks that could negatively impact us.
Offshore 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.
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.
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 finalized regulations targeting new sources of methane emissions from the oil and gas industry, and has issued requests for information on existing sources. 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 could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells. 
Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Our business uses this technique extensively throughout our U.S. operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. 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 2015

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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.

The potential adoption of federal, state and local legislative and regulatory initiatives intended to address potential induced seismic activity in the areas in which we operate could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells. 

State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity.  When caused by human activity, such events are called induced seismicity. Marathon does not currently own or operate water disposal wells in the current areas of interest but does contract for services that regularly inject produced water into underground injection wells. Separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. Marathon does use hydraulic fracturing techniques throughout its U.S. operations.

While the scientific community and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity. For example, Oklahoma has taken numerous regulatory actions in response to concerns related to the operation of produced water disposal wells and induced seismicity, and has issued guidelines to operators in certain areas of the State curtailing injection of produced water due to seismic concerns. Marathon does not currently own or operate injection wells in these areas. Further, Oklahoma recently issued guidelines to operators for management of anomalous seismicity that may be related to hydraulic fracturing activities in the SCOOP/STACK area. In addition, a number of lawsuits have been filed in Oklahoma alleging damage from seismicity relating to disposal well operations. Marathon has not been named in any of those lawsuits.

Increased seismicity in Oklahoma or other areas could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs.  Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and gas activities.
Worldwide political and economic developments and changes in law 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 45% of our crude oil and condensate, NGLs, natural gas and synthetic crude oil volumes related to continuing operations in 2016 was derived from production outside the U.S. and 55% of our proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves as of December 31, 2016 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., Gabon, the Kurdistan Region of Iraq and Libya, and in global markets including:
changes in governmental policies relating to crude oil and condensate, NGLs, natural gas or synthetic crude oil 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.

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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:
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.
As of December 31, 2016, our total debt was $7.3 billion, of which $686 million is due within 12 months. Our indebtedness could have important consequences to our business, including, but not limited to, the following:
we may be more vulnerable to general adverse economic and industry conditions;
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
our flexibility in planning for, or reacting to, changes in our industry may be limited;
a financial covenant in our Credit Agreement stipulates that our total debt to capitalization ratio will not exceed 65% as of the last day of any fiscal quarter, and if exceeded, may make additional borrowings more expensive and affect our ability to plan for and react to changes in the economy and our industry;
we may be at a competitive disadvantage as compared to similar companies that have less debt; and
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 further downgrade in our credit rating could negatively impact our cost of and ability to access capital, which could adversely affect our business.

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We receive debt ratings from the major credit rating agencies in the United States. Due to the decline in crude oil and U.S. natural gas prices in recent years, credit rating agencies reviewed companies in the energy industry, including us. In the first quarter of 2016, our corporate credit rating was downgraded by Standard & Poor's Global Ratings to BBB- (stable) from BBB (stable), by Fitch Ratings to BBB (negative) from BBB+ (stable) and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). On October 11, 2016 Moody's subsequently revised their outlook of our corporate credit rating to stable from negative. The credit rating process is contingent upon a number of factors, many of which are beyond our control. A further downgrade of our credit ratings could negatively impact our cost of capital and our ability to access the capital markets, increase the interest rate and fees we pay on our revolving credit facility, and may limit or reduce credit lines with our bank counterparties. We could also be required to post letters of credit or other forms of collateral for certain contractual obligations, which could increase our costs and decrease our liquidity or letter of credit capacity under our unsecured revolving credit facility. Limitations on our ability to access capital could adversely impact the level of our capital spending program, our ability to manage our debt maturities, or our flexibility to react to changing economic and business conditions.
Our commodity price risk management activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.
Global commodity prices are volatile. In order to mitigate commodity price volatility and increase the predictability of cash flows related to the marketing of our crude oil and natural gas, we, from time to time, enter into crude oil and natural gas hedging arrangements with respect to a portion of our expected production. While hedging arrangements are intended to mitigate commodity price volatility, we may be prevented from fully realizing the benefits of price increases above the price levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Our business could be negatively impacted by 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 crude oil and condensate, NGLs, natural gas and synthetic crude oil 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.
If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
We typically seek the acquisition of crude oil and condensate, NGLs, natural gas and synthetic crude oil 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 crude oil and condensate, NGLs, natural gas and synthetic crude oil 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

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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 crude oil and condensate, NGLs, natural gas and synthetic crude oil 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 our insurance policies will change over time and could escalate. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, due to historical hurricane activity, the availability of insurance coverage for windstorms has changed and, in some instances, it is uneconomical. As a result, our exposure to losses from future windstorm activity has increased.
Litigation by private plaintiffs or government officials could adversely affect our performance.
We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, contract disputes, royalty disputes or any other laws or regulations that apply to our operations. In some cases the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants, and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.

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In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s ability to satisfy its indemnification obligations will not be impaired in the future.
Pursuant to the Separation and Distribution Agreement and the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that MPC agreed to retain or assume, and there can be no assurance that the indemnification from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.
The spin-off could result in substantial tax liability.
We obtained a private letter ruling from the IRS substantially to the effect that the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather, the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also obtained an opinion of outside counsel, substantially to the effect that, the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the Code. The opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by MPC and us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.
If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent of our accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.
Under the terms of the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC is generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment as a result of actions taken, or breaches of representations and warranties made in the Tax Sharing Agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we would be responsible for all such taxes.
We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil common stock.
Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights, including preferences over Marathon Oil common stock respecting dividends and distributions, as our Board of Directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of Marathon Oil common stock. For example, we could grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of the common stock.
Item 1B. Unresolved Staff Comments
None.

26


Item 2. Properties
The location and general character of our principal crude oil and condensate, NGLs 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 a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Environmental Proceedings
The following is a summary of certain proceedings involving us that were pending or contemplated as of December 31, 2016 under federal, state and international 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.
In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations.  We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000 that will be reduced under the terms by mitigating corrective actions.  We do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows. 
In December 2016, we received a letter from the U.K. Department for Business, Energy and Industrial Strategy (“BEIS”) notifying us that they intend to impose a fine of €630,906 for a self-disclosed underreporting of generated carbon dioxide ("CO2") emissions.  We made representations requesting a reduction in this proposed penalty on January 10, 2017. We do not believe that any penalties that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows. 
As of December 31, 2016, we have sites across the country where remediation is being sought under environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation.  Based on currently available information the accrued amount to address the clean-up and remediation costs connected with these sites is not material.
If our assumptions relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts. 
Item 4. Mine Safety Disclosures
Not applicable.

27


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, 2017, there were 35,294 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:
 
2016
 
2015
(Dollars per share)
High Price  
 
Low Price
 
Dividends  
 
High Price  
 
Low Price
 
Dividends  
First Quarter
$12.82
 
$6.73
 
$0.05
 
$29.63
 
$25.47
 
$0.21
Second Quarter
$15.27
 
$10.53
 
$0.05
 
$31.19
 
$25.92
 
$0.21
Third Quarter
$16.80
 
$12.90
 
$0.05
 
$25.79
 
$14.04
 
$0.21
Fourth Quarter
$18.80
 
$12.78
 
$0.05
 
$20.18
 
$12.38
 
$0.05
Full Year
$18.80
 
$6.73
 
$0.20
 
$31.19
 
$12.38
 
$0.68
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, 2016, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
Period
Total Number of
Shares
Purchased(a)
 
Average
Price Paid
per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs(b)
 
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs(b)
10/01/16 – 10/31/16
51,396

 
$15.96
 

 
$
1,500,285,529

11/01/16 – 11/30/16
919

 
$13.20
 

 
$
1,500,285,529

12/01/16 – 12/31/16

 

 

 
$
1,500,285,529

Total
52,315

 
$15.91
 

 
 
(a) 
52,315 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b) 
In January 2006, we announced a $2.0 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, 2016 is $1.5 billion. No repurchases were made under the program in 2016.

28


Item 6.   Selected Financial Data
 
Year Ended December 31,
(In millions, except per share data)
2016
 
2015
 
2014
 
2013
 
2012
Statement of Income Data(a)(b)(c)
 
 

 
 
 
 
 
 
Revenues
$
4,031

 
$
5,522

 
$
10,846

 
$
11,325

 
$
11,966

Income (loss) from continuing operations
(2,140
)
 
(2,204
)
 
969

 
931

 
856

Net income (loss)
(2,140
)
 
(2,204
)
 
3,046

 
1,753

 
1,582

Per Share Data(a)(b)(c)
 
 
 
 
 
 
 
 
 
Basic:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(2.61
)
 
$
(3.26
)
 
$
1.42

 
$
1.32

 
$
1.21

Net income (loss)
$
(2.61
)
 
$
(3.26
)
 
$
4.48

 
$
2.49

 
$
2.24

Diluted:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(2.61
)
 
$
(3.26
)
 
$
1.42

 
$
1.31

 
$
1.21

Net income (loss)
$
(2.61
)
 
$
(3.26
)
 
$
4.46

 
$
2.47

 
$
2.23

Statement of Cash Flows Data(b)
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment related to continuing operations
$
1,245

 
$
3,476

 
$
5,160

 
$
4,443

 
$
4,361

Dividends paid
162

 
460

 
543

 
508

 
480

Dividends per share
$0.20
 
$0.68
 
$0.80
 
$0.72
 
$0.68
Balance Sheet Data at December 31
 
 
 
 
 
 
 
 
 
Total assets
$
31,094

 
$
32,311

 
$
35,983

 
$
35,588

 
$
35,269

Total long-term debt, including capitalized leases
6,589

 
7,276

 
5,295

 
6,362

 
6,475

(a) 
Includes impairments to producing properties of $67 million, $412 million, $132 million, $96 million