10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2017

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

Delaware	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 þNo o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  oNo  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o

Indicate by check mark whether the registrant has submitted electronically 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 þ No o

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.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	(Do not check if a smaller reporting company)
Smaller reporting company o	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o No   þ

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2017: $10,050 million. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.

There were 849,755,866 shares of Marathon Oil Corporation Common Stock outstanding as of February 14, 2018.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2018 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this report.

MARATHON OIL CORPORATION

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

Table of Contents
PART I
	Item 1.	Business	5
	Item 1A.	Risk Factors	16
	Item 1B.	Unresolved Staff Comments	25
	Item 2.	Properties	25
	Item 3.	Legal Proceedings	25
	Item 4.	Mine Safety Disclosures	25
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
	Item 6.	Selected Financial Data	27
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
	Item 8.	Financial Statements and Supplementary Data	53
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	113
	Item 9A.	Controls and Procedures	113
	Item 9B.	Other Information	113
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	114
	Item 11.	Executive Compensation	114
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	115
	Item 14.	Principal Accountant Fees and Services	115
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	116
	Item 16.	Form 10-K Summary	116
		SIGNATURES	117

Definitions

Throughout this report, the following company or industry specific terms and abbreviations are used.

AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea in which we own a 45% equity interest.

AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta, Canada, in which we held a 20% non-operated working interest.

bbl – One stock tank barrel, which is 42 United States gallons liquid volume.

bcf – Billion cubic feet.

boe – Barrels of oil equivalent.

btu – British thermal unit, an energy equivalence measure.

Capital Development Program – Includes capital expenditures, cash investments in equity method investees and other investments, exploration costs that are expensed as incurred rather than capitalized, such as geological and geophysical costs and certain staff costs, and other miscellaneous investment expenditures.

DD&A – Depreciation, depletion and amortization.

Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry well – A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion.

E.G. – Equatorial Guinea.

EGHoldings – Equatorial Guinea LNG Holdings Limited, a liquefied natural gas production company located in E.G. in which we own a 60% equity interest.

EPA – United States Environmental Protection Agency.

E&P – Exploration and production.

Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.

FASB – Financial Accounting Standards Board.

Henry Hub price – a natural gas benchmark price quoted at settlement date average.

IRS – United States Internal Revenue Service.

LNG – Liquefied natural gas.

LPG – Liquefied petroleum gas.

Liquid hydrocarbons or liquids – Collectively, crude oil, condensate and natural gas liquids.

LLS – Louisiana Light Sweet crude oil, an oil index benchmark price as per Bloomberg Finance LLP: LLS St. James.

Marathon Oil – Marathon Oil Corporation and its consolidated subsidiaries: the company as it exists following the June 30, 2011 spin-off of the refining, marketing and transportation operations.

mbbld – Thousand barrels per day.

mboed – Thousand barrels of oil equivalent per day.

mcf – Thousand cubic feet.

mmbbl – Million barrels.

mmboe – Million barrels of oil equivalent.

mmbtu – Million British thermal units.

mmcfd – Million stabilized cubic feet per day.

mmta – Million metric tonnes per annum.

1

MPC –Marathon Petroleum Corporation– the separate independent company, which owns and operates the refining, marketing and transportation operations.

mt – metric tonnes

mtd – metric tonnes per day.

Net acres or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.

NGL or NGLs – Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, which can be collectively removed from produced natural gas, separated into these substances and sold.

NYMEX – New York Mercantile Exchange.

OECD – Organization for Economic Cooperation and Development.

OPEC – Organization of Petroleum Exporting Countries.

Operational availability –A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time, after consideration of internal losses.

Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved reserves – Proved crude oil and condensate, NGLs, natural gas and our historical synthetic crude oil reserves are those quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic viability at greater distances.

Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of liquid hydrocarbons and natural gas produced.

Royalty interest – An interest in an oil or natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SAR or SARs – Stock appreciation right or stock appreciation rights.

SCOOP – South Central Oklahoma Oil Province.

SEC – United States Securities and Exchange Commission.

Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures and 4-D factors in changes that occurred over time).

STACK – Sooner Trend, Anadarko (basin), Canadian (and) Kingfisher (counties).

TD –Total depthor the bottom of a drilled hole.

Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.

U.K. – United Kingdom.

U.S. – United States of America.

2

U.S. resource plays – Consists of our unconventional properties in the Oklahoma, Eagle Ford, Bakken and Northern Delaware.

U.S. GAAP – U.S. Generally Accepted Accounting principles

Working interest – The interest in a mineral property, which gives the owner that share of production from the property. A working interest owner bears that share of the costs of exploration, development and production in return for a share of production. Working interests are sometimes burdened by overriding royalty interests or other interests.

WTI – West Texas Intermediate crude oil, an oil index benchmark price as quoted by NYMEX.

3

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including without limitation: our operational, financial and growth strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, non-core asset sales, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2018 capital development program and the planned allocation thereof; planned capital expenditures and the impact thereof; expectations regarding future economic and market conditions and their effects on us; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and future production and sales expectations, and the drivers thereof. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, these expectations may not prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

• conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;

• changes in expected reserve or production levels;

• changes in political or economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;

• risks relating to our hedging activities;

• capital available for exploration and development;

• drilling and operating risks;

• well production timing;

• availability of drilling rigs, materials and labor, including the costs associated therewith;

• difficulty in obtaining necessary approvals and permits;

• non-performance by third parties of their contractual obligations;

• unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;

• cyber-attacks;

• changes in safety, health, environmental, tax and other regulations;

• other geological, operating and economic considerations; and

• other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty to revise or update any forward-looking statements whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

4

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 the United States, Europe and Africa. Our corporate headquarters is located at 5555 San Felipe Street, Houston, Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our two reportable operating segments are organized and managed based upon geographic location and the nature of the products and services offered. The two segments are:

• United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States;

• International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.

We were incorporated in 2001.

Our strategy is to deliver competitive returns by focusing on the lowest cost, highest margin U.S. resource plays while maintaining a peer-leading balance sheet. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, for a more detailed discussion of our operating results, cash flows and liquidity.

We are concentrated on our core operations in our U.S. unconventional resource plays and E.G. The map below shows the locations of our core operations:

^* Our additional locations include the Gulf of Mexico, U.K., Libya, Gabon and the Kurdistan Region of Iraq.

Segment and Geographic Information

In the second quarter of 2017, we closed on the sale of our Canadian business which includes our Oil Sands Mining segment and exploration stage in-situ leases. The Canadian business is reflected as discontinued operations in all periods presented. Additionally, we have renamed our North America E&P segment to United States E&P segment, effective June 30, 2017. See Item 8. Financial Statements and Supplementary Data – Note 1 to the consolidated financial statements for further detail. For reportable operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements.

In the following discussion regarding our United States E&P and International E&P segments, references to sales or investment indicate our ownership interest or share, as the context requires.

5

United States E&P Segment

We are engaged in oil and gas exploration, development and production activities in the U.S. Our primary focus in the United States E&P segment is concentrated within our four high quality unconventional resource plays. See Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations for further detail on current year results.

United States E&P-- Unconventional Resource Plays

Eagle Ford – We have been operating in the South Texas Eagle Ford play since 2011, where roughly two thirds of our acreage is located in Karnes County and Atascosa County. We operate 32 central gathering and treating facilities across the field that support more than 1,500 producing wells. We also own and operate the Sugarloaf gathering system, a 42-mile natural gas pipeline through the heart of our acreage in Karnes, Atascosa and Bee Counties.

Bakken – We have been operating in North Dakota and eastern Montana since 2006. The majority of our acreage is in core prospects within McKenzie, Mountrail, and Dunn Counties in North Dakota. We continue focusing on the high-return Myrmidon area building on the successes from our enhanced completion designs, as well as delineating our position in Hector.

Oklahoma – Our primary focus in Oklahoma has been delineation and leasehold protection in the Meramec play in the STACK and delineation of the Woodford and Springer plays in the SCOOP, as we move toward infill development. We hold net acreage with rights to the Woodford, Springer, Meramec, Osage, Oswego, Granite Wash and other Pennsylvanian and Mississippian plays, with a majority of this in the SCOOP and STACK.

Northern Delaware – We closed on multiple Permian acquisitions during 2017, with a majority of the acreage in Northern Delaware. These acquisitions give us a strong foundational footprint in the region where we have begun developing the Wolfcamp and Bone Spring plays. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for further detail.

Other United States

Our remaining properties in the United States primarily consist of outside operated assets in the Gulf of Mexico, including the Gunflint field where we hold an 18% non-operated working interest.

International E&P Segment

We are engaged in oil and gas development and production across our international locations primarily in E.G., U.K. and Libya. We include the results of our LPG processing plant, gas liquefaction operations and methanol production operations in E.G. in our International E&P segment.

International E&P

Equatorial Guinea – We own a 63% operated working interest under a production sharing contract in the Alba field and an 80% operated working interest in Block D, both of which are offshore E.G. Block D was unitized with the Alba field in second quarter 2017. Operational availability from our company-operated facilities averaged approximately 99% in 2017.

Equatorial Guinea – Gas Processing – We own a 52% interest in Alba Plant LLC, accounted for as an equity method investment, which operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas, under a long-term contract at a fixed price per btu, is processed by the LPG plant. The LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations.

We also own 60% of EGHoldings and 45% of AMPCO, both accounted for as equity method investments. EGHoldings operates a 3.7 mmta LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to further monetize natural gas production from the Alba field. The LNG production facility sells LNG under a 3.4 mmta sales and purchase agreement. Under the agreement, which runs through 2023, the purchaser takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index. Gross sales of LNG from this production facility totaled approximately 3.95 mmta in 2017. AMPCO had gross sales totaling approximately 1,100 mt in 2017. Methanol production is sold to customers in Europe and the U.S.

United Kingdom – Our operated asset in the U.K. sector of the North Sea is the Brae area complex where we have a 42% working interest in the South, Central, North and West Brae fields, a 39% working interest in the East Brae field, and a 28% working interest in the nearby Braemar field. We own non-operated working interests in the Foinaven area complex, consisting of a 28% working interest in the main Foinaven field, a 47% working interest in East Foinaven and a 20% working interest in the T35 and T25 fields.

6

Libya – We hold a 16% non-operated working interest in the Waha concessions, which includes acreage located in the Sirte Basin of eastern Libya. While civil and political unrest has interrupted operations in recent years, our production resumed in October 2016 at our Waha concession. During December 2016, liftings resumed from the Es Sider crude oil terminal. During 2017 sales volumes and production continued, except for a brief interruption in March 2017 due to civil unrest.

Other International

Kurdistan Region of Iraq – We have non-operated interests in two blocks located north-northwest of Erbil: Atrush with a 15% working interest and Sarsang with a 20% working interest. In 2016, we relinquished to the Kurdistan Regional Government our 45% operated working interest in the Harir block located northeast of Erbil. 

Gabon – We hold a 100% participating interest and operatorship in the Tchicuate block where we have an exploration and production sharing agreement.

In the third quarter 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment, and a portion of this transaction closed during the 4th quarter 2017. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.

Reserves

Proved reserves are required to be disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15% or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent or a continent. Other International ("Other Int’l"), includes the U.K. and the Kurdistan Region of Iraq. Approximately 72% of our proved reserves are located in OECD countries, with 70% located within the U.S.

The following tables set forth estimated quantities of our total proved crude oil and condensate, NGLs and natural gas reserves based upon SEC pricing for period ended December 31, 2017.

		Africa
December 31, 2017	U.S.	E.G.	Libya	Total	Other Int'l	Total from Cont Ops
Proved Developed Reserves
Crude oil and condensate (mmbbl)	263	39	165	204	17	484
Natural gas liquids (mmbbl)	118	25	—	25	—	143
Natural gas (bcf)	726	833	94	927	2	1,655
Total proved developed reserves  (mmboe)	502	203	181	384	17	903
Proved Undeveloped Reserves
Crude oil and condensate (mmbbl)	307	—	—	—	9	316
Natural gas liquids (mmbbl)	111	—	—	—	—	111
Natural gas (bcf)	598	—	110	110	6	714
Total proved undeveloped reserves  (mmboe)	518	—	18	18	10	546
Total Proved Reserves
Crude oil and condensate (mmbbl)	570	39	165	204	26	800
Natural gas liquids (mmbbl)	229	25	—	25	—	254
Natural gas (bcf)	1,324	833	204	1,037	8	2,369
Total proved reserves (mmboe)	1,020	203	199	402	27	1,449

Of the total estimated proved reserves, approximately 55% was crude oil and condensate. As of December 31, 2017, our estimated proved developed reserves totaled 903 mmboe or 62% and estimated proved undeveloped reserves totaling 546 mmboe or 38% of our total proved reserves. For additional detail on reserves, see Item 8. Financial Statements and Supplementary Data - Supplementary Information on Oil and gas Producing Activities.

7

Productive and Drilling Wells

For our United States E&P and International E&P segments, the following table sets forth gross and net productive wells, service wells and drilling wells as of December 31 for the years presented.

	Productive Wells
	Oil		Natural Gas		Service Wells		Drilling Wells
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2017
U.S.	5,132	1,905	1,690	676	799	70	33	13
E.G.	—	—	19	12	—	—	—	—
Libya	1,071	175	7	2	94	16	—	—
Total Africa	1,071	175	26	14	94	16	—	—
Other International	61	22	19	7	23	8	—	—
Total	6,264	2,102	1,735	697	916	94	33	13
2016
U.S. (a)	4,533	1,650	1,830	708	821	85
E.G.	—	—	17	11	2	1
Libya	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
2015
U.S.	7,198	2,878	1,796	750	2,727	747
E.G.	—	—	17	11	2	1
Libya	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

^(a)  Reduction in December 31, 2016 gross and net productive wells and service wells is primarily due to the dispositions of certain conventional West Texas and Wyoming assets in 2016. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.

8

Drilling Activity

For our United States E&P and International E&P segments, the table below sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed as of December 31 for the years represented.

	Development				Exploratory
	Oil	Natural Gas	Dry	Total	Oil	Natural Gas	Dry	Total	Total
2017
U.S.	107	27	—	134	88	16	—	104	238
E.G.	—	—	—	—	—	—	—	—	—
Libya	—	—	—	—	—	—	—	—	—
Total Africa	—	—		—	—	—	—	—	—
Other International	—	—	—	—	—	—	—	—	—
Total	107	27	—	134	88	16	—	104	238
2016
U.S.	64	12	—	76	70	27	—	97	173
E.G.	—	—	—	—	—	—	—	—	—
Libya	—	—	—	—	—	—	—	—	—
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
Libya	—	—	—	—	—	—	—	—	—
Total Africa	—	1	—	1	—	—	1	1	2
Other International	1	—	—	1	—	—	—	—	1
Total	136	37	11	184	49	48	2	99	283

Acreage

We believe we have satisfactory title to our United States E&P and International E&P properties in accordance with standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time which may result in litigation. In the case of undeveloped properties, an investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Our title to properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry. In addition, our interests may be subject to obligations or duties under applicable laws or burdens such as net profits interests, liens related to operating agreements, development obligations or capital commitments under international production sharing contracts or exploration licenses.

The following table sets forth, by geographic area, the gross and net developed and undeveloped acreage held in our United States E&P and International E&P segments as of December 31, 2017.

	Developed		Undeveloped		Developed and Undeveloped
(In thousands)	Gross	Net	Gross	Net	Gross	Net
U.S.	1,529	1,008	388	322	1,917	1,330
E.G.	82	67	54	36	136	103
Libya	12,909	2,108	—	—	12,909	2,108
Other Africa	—	—	277	277	277	277
Total Africa	12,991	2,175	331	313	13,322	2,488
Other International	86	31	171	32	257	63
Total	14,606	3,214	890	667	15,496	3,881

9

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

Net Sales Volumes

		Africa
	U.S.	E.G.	Libya	Other Int'l	Cont Ops	Disc Ops	Total
Year Ended December 31,
2017
Crude and condensate (mbbld)(a)	133	21	19	12	185	—	185
Natural gas liquids (mbbld)	43	11	—	1	55	—	55
Natural gas (mmcfd)(b)	348	459	4	22	833	—	833
Synthetic crude oil (mbbld)(c)	—	—	—	—	—	18	18
Total sales volumes (mboed)	234	109	20	16	379	18	397
2016
Crude and condensate (mbbld)(a)	131	20	3	12	166	—	166
Natural gas liquids (mbbld)	40	11	—	—	51	—	51
Natural gas (mmcfd)(b)	314	425	—	28	767	—	767
Synthetic crude oil (mbbld)(c)	—	—	—	—	—	48	48
Total sales volumes (mboed)	223	102	3	17	345	48	393
2015
Crude and condensate (mbbld)(a)	171	19	—	14	204	—	204
Natural gas liquids (mbbld)	39	10	—	—	49	—	49
Natural gas (mmcfd)(b)	351	410	—	21	782	—	782
Synthetic crude oil (mbbld)(c)	—	—	—	—	—	45	45
Total sales volumes (mboed)	269	97	—	18	384	45	429

^(a)  The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

^(b)  Includes natural gas acquired for injection and subsequent resale.

^(c)  Upgraded bitumen excluding blendstocks.

Average Production Cost per Unit ^(a) 

			Africa
(Dollars per boe)	U.S.		E.G.		Libya		Other Int'l		Cont Ops		Disc Ops		Total
2017	$	9.49	$	2.12	$	6.08	$	26.61	$	7.90	$	29.72	$	9.23
2016	9.84		2.17		N.M.		23.13		8.41		29.36		11.02
2015	10.65		2.37		N.M.		27.23		9.54		38.42		12.62

^(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.

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Average Sales Price per Unit^(a) 

			Africa
(Dollars per unit)	U.S.		E.G.			Libya		Total		Other Int'l		Disc Ops		Total
2017
Crude and condensate (bbl)	$	49.35	$	46.02		$	60.72	$	53.11	$	52.66	$	—	$	50.38
Natural gas liquids (bbl)	20.55		1.00		(b)	—		1.00		39.65		—		16.65
Natural gas (mcf)	2.84		0.24		(b)	5.03		0.28		6.28		—		1.51
Synthetic crude oil (bbl)	—		—			—		—		—		47.39		47.39
2016
Crude and condensate (bbl)	$	38.57	$	38.85		$	57.69	$	40.95	$	43.21	$	—	$	39.23
Natural gas liquids (bbl)	13.15		1.00		(b)	—		1.00		26.41		—		10.68
Natural gas (mcf)	2.38		0.24		(b)	—		0.24		4.80		—		1.26
Synthetic crude oil (bbl)	—		—			—		—		—		37.57		37.57
2015
Crude and condensate (bbl)	$	43.50	$	42.83		$	—	$	42.83	$	53.91	$	—	$	44.14
Natural gas liquids (bbl)	13.37		1.00		(b)	—		1.00		32.53		—		11.16
Natural gas (mcf)	2.66		0.24		(b)	—		0.24		6.85		—		1.50
Synthetic crude oil (bbl)	—		—			—		—		—		40.13		40.13

^(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 and natural gas. These activities include the transportation of production to market centers, the sale of commodities to third parties and the storage of production. We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the purchase of commodities from third parties for resale.

Gross Delivery Commitments

We have committed to deliver gross quantities of crude oil and condensate, NGLs and natural gas to customers under a variety of contracts. As of December 31, 2017, the contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to the following commitments:

	2018	2019	2020	Thereafter	Commitment Period Through
Eagle Ford
Crude and condensate (mbbld)	95	65	51	—	2020
Natural gas liquids (mbbld)	1	1	—	—	2020
Natural gas (mmcfd)	168	168	168	46 - 70	2022
Bakken
Crude and condensate (mbbld)	10	10	10	5 - 10	2027
Natural gas (mmcfd)	2	2	2	2 - 25	2027
Oklahoma
Natural gas (mmcfd)	—	90	118	110 - 148	2030

All of these contracts provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate. In addition to the contracts discussed above, we have entered into numerous agreements for transportation and processing of our equity production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms.

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Competition

Competition exists in all sectors of the oil and gas industry and we compete with major integrated and independent oil and gas companies, as well as national oil companies. We compete, in particular, in the exploration for and development of new reserves, acquisition of oil and natural gas leases and other properties, the marketing and delivery of our production into worldwide commodity markets and for the labor and equipment required for exploration and development of those properties. Principal methods of competing include geological, geophysical, and engineering research and technology, experience and expertise, economic analysis in connection with portfolio management, and safely operating oil and gas producing properties. See Item 1A. Risk Factors for discussion of specific areas in which we compete and related risks.

Environmental, Health and Safety Matters

The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety matters. Our Corporate Health, Environment, Safety and Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and safety at the national, state and local levels. These laws and their implementing regulations and other similar state and local laws and rules can impose certain operational controls for minimization of pollution or recordkeeping, monitoring and reporting requirements or other operational or siting constraints on our business, result in costs to remediate releases of regulated substances, including crude oil, into the environment, or require costs to remediate sites to which we sent regulated substances for disposal. In some cases, these laws can impose strict liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others (such as prior owners or operators of our assets) or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.

New laws have been enacted and regulations are being adopted by various regulatory agencies on a continuing basis and the costs of compliance with these new laws and regulations can only be broadly appraised until their implementation becomes more defined.

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

Air and Climate Change

Environmental advocacy groups and regulatory agencies in the United States and other countries have focused considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their potential role in climate change. Developments in greenhouse gas initiatives may affect us and other similarly situated companies operating in the oil and gas industry. As part of our commitment to environmental stewardship, we estimate and publicly report greenhouse gas emissions from our operations. We are working to continuously improve the accuracy and completeness of these estimates. In addition, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable and cost effective.

Government entities have filed lawsuits in California and New York seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Marathon Oil has been named as a defendant in six of these lawsuits in California, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operations or cash flow.

The EPA finalized a more stringent National Ambient Air Quality Standard ("NAAQS") for ozone in October 2015. This more stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which we operate, which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. The EPA anticipates promulgating final area designations under the new standard in the first half of 2018. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with this revised regulation, the extent and magnitude of

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that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented. The EPA's final rule has been judicially challenged by both industry and other interested parties, and the outcome of this litigation may also impact implementation and revisions to the rule.

In November 2016, the Bureau of Land Management (“BLM”) issued a final rule to further restrict venting and/or flaring of gas from facilities subject to BLM jurisdiction, and to modify certain royalty requirements.  BLM issued a two-year stay of these requirements in December 2017 and has indicated that the requirements could be rescinded or significantly revised in the future. If not withdrawn or significantly revised, this rule is expected to result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.  If we are unable to comply with the terms of these regulations, we could be required to forego certain operations. These regulations may also result in administrative, civil and/or criminal penalties for non-compliance.

Hydraulic Fracturing

Hydraulic fracturing is a commonly used process that involves injecting water, sand and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Our business uses this technique extensively throughout our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Various state and local-level initiatives in regions with substantial shale resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.

Water

In 2014, the EPA and the U.S. Army Corps of Engineers published proposed regulations which expand the surface waters that are regulated under the Clean Water Act ("CWA") and its various programs. While these regulations were finalized largely as proposed in 2015, the rule has been stayed by the courts pending a substantive decision on the merits. If this rule is ultimately implemented, the expansion of CWA jurisdiction will result in additional costs of compliance as well as increased monitoring, recordkeeping and recording for some of our facilities.

For additional information, see Item 1A. Risk Factors.

Concentrations of Credit Risk

We are exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. In 2017, sales to Vitol and each of their respective affiliates accounted for approximately 10% of our total revenues. In 2016, sales to Valero Marketing and Supply, Tesoro Petroleum, and Flint Hills Resources and each of their respective affiliates accounted for approximately 13%, 11% and 10% of our total revenues. In 2015, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues.

Trademarks, Patents and Licenses

We currently hold a number of U.S. and foreign patents. Although in the aggregate our trademarks, patents and licenses are important to us, we do not regard any single trademark, patent, license or group of related trademarks, patents or licenses as critical or essential to our business as a whole.

Employees

We had approximately 2,300 active, full-time employees as of December 31, 2017.

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Executive Officers of the Registrant

The executive officers of Marathon Oil and their ages as of February 1, 2018, are as follows:

Lee M. Tillman	56	President and Chief Executive Officer
Dane E. Whitehead	56	Executive Vice President and Chief Financial Officer
T. Mitch Little	54	Executive Vice President—Operations
Reginald D. Hedgebeth	50	Senior Vice President, General Counsel and Secretary
Patrick J. Wagner	53	Executive Vice President-Corporate Development and Strategy
Catherine L. Krajicek	56	Vice President—Conventional
Gary E. Wilson	56	Vice President, Controller and Chief Accounting Officer

Mr. Tillman was appointed president and chief executive officer in August 2013.  Mr. Tillman is also a member of our Board of Directors.  Prior to this appointment, Mr. Tillman served as vice president of engineering for ExxonMobil Development Company (a project design and execution company), where he was responsible for all global engineering staff engaged in major project concept selection, front-end design and engineering.  Between 2007 and 2010, Mr. Tillman served as North Sea production manager and lead country manager for subsidiaries of ExxonMobil in Stavanger, Norway.  Mr. Tillman began his career in the oil and gas industry at Exxon Corporation in 1989 as a research engineer and has extensive operations management and leadership experience.

Mr. Whitehead was appointed executive vice president and chief financial officer in March 2017. Prior to this appointment, Mr. Whitehead served as executive vice president and chief financial officer of both EP Energy Corp. and EP Energy LLC (oil and natural gas producer) since May 2012. Between 2009 and 2012 Mr. Whitehead served as senior vice president of strategy and enterprise business development and a member of El Paso Corporation's executive committee. He joined El Paso Exploration & Production Company as senior vice president and chief financial officer in 2006. Before joining El Paso Mr. Whitehead was vice president, controller and chief accounting officer of Burlington Resources Inc. (oil and natural gas producer), and formerly senior vice president and CFO of Burlington Resources Canada.

Mr. Little was appointed executive vice president of operations in August 2016 after having served as vice president, conventional since December 2015, vice president international and offshore exploration and production operations since September 2013, and as vice president, international production operations since September 2012. Prior to that, Mr. Little was resident manager of our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little joined Marathon Oil in 1986 and has since held a number of engineering and management positions of increasing responsibility.

Mr. Hedgebeth was appointed senior vice president, general counsel and secretary in April 2017. Between 2009 and 2017 Mr. Hedgebeth served as general counsel, corporate secretary and chief compliance officer for Spectra Energy Corp (oil and natural gas pipeline company) and general counsel for Spectra Energy Partners, LP. Before joining Spectra Energy Mr. Hedgebeth served as senior vice president, general counsel and secretary with Circuit City Stores, Inc. (consumer electronics company), and vice president of legal for The Home Depot, Inc. (home improvement supplies retailing company).

Mr. Wagner was appointed executive vice president of corporate development and strategy in November 2017 after having served as senior vice president of corporate development and strategy since March 2017, vice president of corporate development and interim chief financial officer since August 2016 and vice president of corporate development since April 2014. Prior to this appointment, he served as senior vice president, western business unit, for QR Energy LP (an oil and natural gas producer) and the affiliated Quantum Resources Management, which he joined in early 2012 as vice president, exploitation. Prior to that, Mr. Wagner was managing director in Houston for Scotia Waterous, the oil and gas arm of Scotiabank (an international banking services provider), from 2010 to 2012. Before joining Scotia, Mr. Wagner was vice president, Gulf of Mexico, for Devon Energy Corp. (an oil and natural gas producer), having joined Devon in 2003 as manager, international exploitation.

Ms. Krajicek was appointed vice president—conventional assets in August 2016 after having served as vice president of technology and innovation since December 2015. Prior to that, Ms. Krajicek served as vice president, health, environment, safety and security from January 2015 through December 2015. In January 2018 Ms. Krajicek announced her plans to retire effective April 1, 2018. Ms. Krajicek joined Marathon Oil in 2007 and has since held a number of positions of increasing responsibility. Prior to joining the Company, Ms. Krajicek spent 22 years with Conoco and then ConocoPhillips (a multinational energy corporation), where she held a variety of reservoir engineering and asset management and development management positions for upstream and mid-stream businesses under development, both in the U.S. and internationally.

Mr. Wilson was appointed vice president, controller and chief accounting officer in October 2014. Prior to joining Marathon Oil, he served in various finance and accounting positions of increasing responsibility at Noble Energy, Inc. (a global exploration and production company) since 2001, including as director corporate accounting from February 2014 through September 2014, director global operations services finance from October 2012 through February 2014, director controls and

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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.

A substantial decline in crude oil and condensate, NGLs and natural gas prices would reduce our operating results and cash flows and could adversely impact our future rate of growth and the carrying value of our assets.

The markets for crude oil and condensate, NGLs and natural gas have been volatile and are likely to continue to be volatile in the future, causing prices to fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil and condensate, NGLs and natural gas. Many of the factors influencing prices of crude oil and condensate, NGLs and natural gas are beyond our control. These factors include:

• worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas;

• the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas;

• the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls;

• the production levels of non-OPEC countries, including production levels in the shale plays in the United States;

• the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;

• political instability or armed conflict in oil and natural gas producing regions;

• changes in weather patterns and climate;

• natural disasters such as hurricanes and tornadoes;

• the price and availability of alternative and competing forms of energy;

• the effect of conservation efforts;

• epidemics or pandemics;

• technological advances affecting energy consumption and energy supply;

• domestic and foreign governmental regulations and taxes; and

• general economic conditions worldwide.

The long-term effects of these and other factors on the prices of crude oil and condensate, NGLs and natural gas are uncertain. Historical declines in commodity prices have adversely affected our business by:

• reducing the amount of crude oil and condensate, NGLs and natural gas that we can produce economically;

• reducing our revenues, operating income and cash flows;

• causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;

• requiring us to impair the carrying value of our assets;

• reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and natural gas; and

• increasing the costs of obtaining capital, such as equity and short- and long-term debt.

Estimates of crude oil and condensate, NGLs and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our reserves.

The proved reserve information included in this Annual Report on Form 10-K has been derived from engineering and geoscience estimates. Estimates of crude oil and condensate, NGLs, natural gas and our historical synthetic crude oil reserves were prepared, in accordance with SEC regulations, by our in-house teams of reservoir engineers and geoscience professionals and were reviewed and approved by our Corporate Reserves Group and third-party consultants. Prior to 2016, the synthetic

16

crude oil reserves estimates, included in discontinued operations, were prepared by GLJ, a third-party consulting firm experienced in working with oil sands. Reserves were valued based on SEC pricing for the periods ended December 31, 2017, 2016 and 2015, as well as other conditions in existence at those dates. The table below provides the 2017 SEC pricing for certain benchmark prices:

	SEC Pricing 2017
WTI Crude oil (per bbl)	$	51.34
Henry Hub natural gas (per mmbtu)	$	2.98
Brent crude oil (per bbl)	$	54.39
Mont Belvieu NGLs (per bbl)	$	22.03

If commodity prices were to decrease by approximately 10% below average prices used to estimate 2017 proved reserves (see table above), we would not expect price related reserve revisions to have a material impact on proved reserve volumes. Future reserve revisions could also result from changes in capital funding, drilling plans and governmental regulation, among other things.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be directly measured. Estimates of economically producible reserves and of future net cash flows depend on a number of variable factors and assumptions, including:

• location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;

• historical production from the area, compared with production from other analogous producing areas;

• the assumed impacts of regulation by governmental agencies;

• assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and

• industry economic conditions, levels of cash flows from operations and other operating considerations.

As a result, different petroleum engineers and geoscientists, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ materially from the estimated amounts:

• the amount and timing of production;

• the revenues and costs associated with that production; and

• the amount and timing of future development expenditures.

If we are unsuccessful in acquiring or finding additional reserves, our future crude oil and condensate, NGLs and natural gas production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.

The rate of production from crude oil and condensate, NGLs and natural gas properties generally declines as reserves are depleted. Except to the extent we acquire interests in additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, optimize production performance or identify additional reservoirs not currently producing or secondary recovery reserves, our proved reserves will decline materially as crude oil and condensate, NGLs and natural gas are produced. Accordingly, to the extent we are not successful in replacing the crude oil and condensate, NGLs and natural gas we produce, our future revenues will decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:

• obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas in promising areas;

• drilling success;

• the ability to complete projects timely and cost effectively;

• the ability to find or acquire additional proved reserves at acceptable costs; and

• the ability to fund such activity.

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Future exploration and drilling results are uncertain and involve substantial costs.

Drilling for crude oil and condensate, NGLs and natural gas involves numerous risks, including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• inflation in exploration and drilling costs;

• fires, explosions, blowouts or surface cratering;

• lack of access to pipelines or other transportation methods; and

• shortages or delays in the availability of services or delivery of equipment.

If crude oil and condensate, NGLs and natural gas prices decrease, it could adversely affect the abilities of our counterparties to perform their obligations to us, including abandonment obligations, which could negatively impact our financial results.

We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production, or transportation of crude oil and condensate, NGLs and natural gas, with partners and other counterparties in order to share risks associated with those operations. In addition, we market our products to a variety of purchasers. If commodity prices decrease, some of our counterparties may experience liquidity problems and may not be able to meet their financial and other obligations, including abandonment obligations, to us. The inability of our joint venture partners to fund their portion of the costs under our joint venture agreements, or the nonperformance by purchasers, contractors or other counterparties of their obligations to us, could negatively impact our operating results and cash flows.

If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving drilling and completion activities, engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:

• denial of or delay in receiving requisite regulatory approvals and/or permits;

• unplanned increases in the cost of construction materials or labor;

• disruptions in transportation of components or construction materials;

• increased costs or operational delays resulting from shortages of water;

• adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;

• shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

• market-related increases in a project’s debt or equity financing costs; and

• nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.

Any one or more of these factors could have a significant impact on our capital projects.

Our offshore operations involve special risks that could negatively impact us.

Offshore operations present technological challenges and operating risks because of the marine environment.  Activities in deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and the physical distance to oilfield service infrastructure and service providers.  Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities.

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We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in environmental, health, safety and security laws and regulations, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Our businesses are subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the venting or flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions and the protection of endangered species as well as laws, regulations, and other requirements relating to public and employee safety and health and to facility security. We have incurred and may continue to incur capital, operating and maintenance, and remediation expenditures as a result of these laws, regulations, and other requirements. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results will be adversely affected. The specific impact of these laws, regulations, and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations, and other requirements could result in civil penalties or criminal fines and other enforcement actions against us.

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Our operations result in greenhouse gas emissions. Currently, various legislative or regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in countries where we operate, including the U.S. and the European Union. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered. The EPA has also finalized regulations targeting new sources of methane emissions from the oil and gas industry. Finalization of new legislation, regulations or international agreements in the future could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and condensate, NGLs and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.

The potential adoption of federal, state and local legislative and regulatory initiatives related to hydraulic fracturing could result in increased compliance costs, operating restrictions or delays in the completion of oil and gas wells. 

Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Our business uses this technique extensively throughout our U.S. operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Various state and local-level initiatives in regions with substantial shale resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. In 2015 the BLM issued a rule governing certain hydraulic fracturing practices on lands within their jurisdiction; however, this rule was rescinded in December 2017.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and condensate, NGLs and natural gas, including from the shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells.

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

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State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity.  When caused by human activity, such events are called induced seismicity. Separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to anomalous seismic events. Marathon uses hydraulic fracturing techniques throughout its U.S. operations.

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

Increased seismicity in Oklahoma or other areas could result in additional regulation and restrictions on our operations and could lead to operational delays or increased operating costs.  Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and gas activities.

Worldwide political and economic developments and changes in law or policy could adversely affect our operations and materially reduce our profitability and cash flows.

Local political and economic factors in global markets could have a material adverse effect on us. A total of 38% of our crude oil and condensate, NGLs and natural gas related to continuing operations in 2017 was derived from production outside the U.S. and 30% of our proved reserves of crude oil and condensate, NGLs and natural gas as of December 31, 2017 were located outside the U.S. We are, therefore, subject to the political, geographic and economic risks and possible terrorist activities or other armed conflict attendant to doing business within or outside of the U.S. There are many risks associated with operations in countries such as E.G., Gabon, the Kurdistan Region of Iraq and Libya, and in global markets including:

• changes in governmental policies relating to crude oil and condensate, NGLs or natural gas and taxation;

• other political, economic or diplomatic developments and international monetary fluctuations;

• political and economic instability, war, acts of terrorism, armed conflict and civil disturbances;

• the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and

• fluctuating currency values, hard currency shortages and currency controls.

For the past several years, there have been varying degrees of political instability and public protests, including demonstrations which have been marked by violence and numerous incidences of terrorist acts, within some countries in the Middle East and Africa. Some political regimes in these countries are threatened or have changed as a result of such unrest.

If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in governments that are hostile to the U.S. These may have the following results, among others:

• volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates and reduced demand for our products;

• negative impact on the world crude oil supply if transportation avenues are disrupted;

• security concerns leading to the prolonged evacuation of our personnel;

• damage to, or the inability to access, production facilities or other operating assets; and

• inability of our service and equipment providers to deliver items necessary for us to conduct our operations.

Continued hostilities in the Middle East and Africa and the occurrence or threat of future terrorist attacks, or other armed conflict, could adversely affect the economies of the U.S. and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. These risks could lead to increased volatility in prices for crude oil and condensate, NGLs and natural gas. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.

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Actions of governments through tax legislation or interpretations of tax law, and other changes in law, executive order and commercial restrictions could reduce our operating profitability, both in the U.S. and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries and will continue to do so in the future. Changes in law could also adversely affect our results, including new regulations resulting in higher costs to transport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.

Our level of indebtedness may limit our liquidity and financial flexibility.

As of December 31, 2017, our total debt was $5.5 billion, with no debt due within the next 24 months. Our indebtedness could have important consequences to our business, including, but not limited to, the following:

• we may be more vulnerable to general adverse economic and industry conditions;

• 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 and natural gas prices, and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt. See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for a discussion of debt obligations.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital, which could adversely affect our business.

We receive debt ratings from the major credit rating agencies in the United States. Due to the decline in crude oil and U.S. natural gas prices in recent years, credit rating agencies reviewed companies in the energy industry, including us. At December 31, 2017, our corporate credit ratings were: Standard & Poor's Global Ratings Services BBB- (stable); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (stable). The credit rating process is contingent upon a number of factors, many of which are beyond our control. A downgrade of our credit ratings could negatively impact our cost of capital and our ability to access the capital markets, increase the interest rate and fees we pay on our revolving credit facility, and may limit or reduce credit lines with our bank counterparties. We could also be required to post letters of credit or other forms of collateral for certain contractual obligations, which could increase our costs and decrease our liquidity or letter of credit capacity under our unsecured revolving credit facility. Limitations on our ability to access capital could adversely impact the level of our capital spending program, our ability to manage our debt maturities, or our flexibility to react to changing economic and business conditions.

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Our commodity price risk management activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.

Global commodity prices are volatile. In order to mitigate commodity price volatility and increase the predictability of cash flows related to the marketing of our crude oil and natural gas, we, from time to time, enter into crude oil and natural gas hedging arrangements with respect to a portion of our expected production. While hedging arrangements are intended to mitigate commodity price volatility, we may be prevented from fully realizing the benefits of price increases above the price levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Our business could be negatively impacted by cyberattacks targeting our computer and telecommunications systems and infrastructure, or targeting those of our third-party service providers.

Our business, like other companies in the oil and gas industry, has become increasingly dependent on digital technologies, including technologies that are managed by third-party service providers on whom we rely to help us collect, host or process information. Such technologies are integrated into our business operations and used as a part of our production and distribution systems in the U.S. and abroad, including those systems used to transport production to market, to enable communications, and to provide a host of other support services for our business. Use of the internet and other public networks for communications, services, and storage, including “cloud” computing, exposes all users (including our business) to cybersecurity risks.

While we and our third-party service providers commit resources to the design, implementation, and monitoring of our information systems, there is no guarantee that our security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect, or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using techniques designed to circumvent controls and avoid detection. We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in information security breaches and significant disruption to our business. Our information systems and related infrastructure have experienced attempted and actual minor breaches of our cybersecurity in the past, but we have not suffered any losses or breaches which had a material effect on our business, operations or reputation relating to such attacks; however, there is no assurance that we will not suffer such losses or breaches in the future. 

As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to investigate and remediate any information systems and related infrastructure security vulnerabilities. We may also be subject to regulatory investigations or litigation relating from cybersecurity issues.

Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.

The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities, rail cars, trucks and vessels. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our crude oil and condensate, NGLs and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production. Both the cost and availability of pipelines, rail cars, trucks, or vessels to transport our crude oil could be adversely impacted by new and expected state or federal regulations relating to transportation of crude oil.

If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.

We typically seek the acquisition of crude oil and natural gas properties and leases.  Although we perform reviews of properties to be acquired in a manner that we believe is diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit us to become sufficiently familiar with the properties in order to fully assess possible deficiencies and potential problems.  Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.  Moreover, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas (as previously discussed), actual future production rates and associated costs with respect to acquired properties.  Actual reserves, production rates and costs may vary substantially from those assumed in our estimates.  In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

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We operate in a highly competitive industry, and many of our competitors are larger and have available resources in excess of our own.

The oil and gas industry is highly competitive, and many competitors, including major integrated and independent oil and gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. We also compete with these companies for equipment and personnel, including petroleum engineers, geologists, geophysicists and other specialists, required to develop and operate those properties and in the marketing of crude oil and condensate, NGLs and natural gas to end-users. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties. They may also be able to use their greater resources to attract and retain experienced personnel.

Many of our major projects and operations are conducted with partners, which may decrease our ability to manage risk.

We often enter into arrangements to conduct certain business operations, such as oil and gas exploration and production with partners in order to share risks associated with those operations. However, these arrangements also may decrease our ability to manage risks and costs, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. In addition, misconduct, fraud, noncompliance with applicable laws and regulations or improper activities by or on behalf of one or more of our partners could have a significant negative impact on our business and reputation.

Our operations are subject to business interruptions and casualty losses. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities and increased costs.

Our United States E&P and International E&P operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, tornadoes, hurricanes and other adverse weather, tsunamis, earthquakes, volcanic eruptions or nuclear or other disasters, labor disputes and accidents. These same risks can be applied to the third-parties which transport our products from our facilities. A prolonged disruption in the ability of any pipelines, rail cars, trucks, or vessels to transport our production could contribute to a business interruption or increase costs.

Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Various hazards have adversely affected us in the past, and damages resulting from a catastrophic occurrence in the future involving us or any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially large claims or in our being assessed potentially substantial fines by governmental authorities. We maintain insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we have maintained insurance coverage for physical damage including at times resulting business interruption to our major onshore and offshore facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for our insurance policies will change over time and could escalate. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, due to historical hurricane activity, the availability of insurance coverage for windstorms has changed and, in some instances, it is uneconomical. As a result, our exposure to losses from future windstorm activity has increased.

Litigation by private plaintiffs or government officials or entities could adversely affect our performance.

We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, contract disputes, royalty disputes or any other laws or regulations that apply to our operations. In some cases the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants, and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.

For instance, government entities have filed lawsuits in California and New York seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Marathon Oil has been named as a defendant in six of these lawsuits in California, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. The ultimate outcome and impact to us cannot

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be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.

In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s ability to satisfy its indemnification obligations will not be impaired in the future.

Pursuant to the Separation and Distribution Agreement and the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that MPC agreed to retain or assume, and there can be no assurance that the indemnification from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.

The spin-off could result in substantial tax liability.

We obtained a private letter ruling from the IRS substantially to the effect that the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather, the private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also obtained an opinion of outside counsel, substantially to the effect that, the distribution of shares of MPC common stock in the spin-off qualified as tax free to MPC, us and our stockholders for U.S. federal income tax purposes under Sections 355 and 368 and related provisions of the Code. The opinion relied on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by MPC and us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion is not binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.

If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent of our accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.

Under the terms of the Tax Sharing Agreement we entered into with MPC in connection with the spin-off, MPC is generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment as a result of actions taken, or breaches of representations and warranties made in the Tax Sharing Agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we would be responsible for all such taxes.

We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil common stock.

Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights, including preferences over Marathon Oil common stock respecting dividends and distributions, as our Board of Directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of Marathon Oil common stock. For example, we could grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of the common stock.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our principal crude oil and condensate, NGLs and natural gas properties and facilities, and other important physical properties have been described by segment under Item 1. Business.

Estimated net proved crude oil and condensate, NGLs and natural gas reserves are set forth in Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.

Item 3. Legal Proceedings

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

See Item 8. Financial Statements and Supplementary Data – Note 24 to the consolidated financial statements for a description of such legal and administrative proceedings.

Environmental Proceedings

The following is a summary of certain proceedings involving us that were pending or contemplated as of December 31, 2017, under federal and state environmental laws.

Government entities have filed lawsuits in California and New York seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the greenhouse gas emissions attributable to those fuels. The lawsuits allege damages as a result of global warming and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Marathon Oil has been named as a defendant in six of these lawsuits in California, along with numerous other companies. Similar lawsuits may be filed in other jurisdictions. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the claims made against us are without merit and will not have a material adverse effect on our consolidated financial position, results of operations or cash flow.

As of December 31, 2017, we have sites across the country where remediation is being sought under environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation.  Based on currently available information the accrued amount to address the clean-up and remediation costs connected with these sites is not material.

If our assumptions relating to these costs prove to be inaccurate, future expenditures may exceed our accrued amounts. 

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange ("NYSE"). As of January 31, 2018, there were 31,472 registered holders of Marathon Oil common stock.

The following table reflects high and low sales prices for Marathon Oil common stock and the related dividend per share by quarter for the past two years:

	2017			2016
(Dollars per share)	High Price	Low Price	Dividends	High Price	Low Price	Dividends
First Quarter	$18.18	$14.61	$0.05	$12.82	$6.73	$0.05
Second Quarter	$16.60	$11.35	$0.05	$15.27	$10.53	$0.05
Third Quarter	$13.73	$10.77	$0.05	$16.80	$12.90	$0.05
Fourth Quarter	$17.26	$13.48	$0.05	$18.80	$12.78	$0.05
Full Year	$18.18	$10.77	$0.20	$18.80	$6.73	$0.20

Dividends – Our Board of Directors intends to declare and pay dividends on Marathon Oil common stock based on our financial condition and results of operations, although it has no obligation under Delaware law or the Restated Certificate of Incorporation to do so. In determining our dividend policy, the Board will rely on our consolidated financial statements. Dividends on Marathon Oil common stock are limited to our legally available funds.

The following table provides information about purchases by Marathon Oil and its affiliated purchaser, during the quarter ended December 31, 2017, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:

Period	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)
10/01/17 – 10/31/17	49,046	$13.38	—	$	1,500,285,529
11/01/17 – 11/30/17	2,813	$14.62	—	$	1,500,285,529
12/01/17 – 12/31/17	—	—	—	$	1,500,285,529
Total	51,859	$13.45	—

^(a)  51,859 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, 2017 is $1.5 billion. No repurchases were made under the program in 2017.

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Item 6.   Selected Financial Data

	Year Ended December 31,
(In millions, except per share data)	2017			2016			2015			2014			2013
Statement of Income Data(a)(b)(c)
Revenues	$	4,373		$	3,170		$	4,635		$	9,238		$	9,731
Income (loss) from continuing operations	(830		)	(2,087		)	(1,701		)	710			710
Discontinued operations	(4,893		)	(53		)	(503		)	2,336			1,043
Net income (loss)	(5,723		)	(2,140		)	(2,204		)	3,046			1,753
Per Share Data(a)(b)(c)
Basic:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)	$	1.04		$	1.01
Discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)	$	3.44		$	1.48
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)	$	4.48		$	2.49
Diluted:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)	$	1.04		$	1.00
Discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)	$	3.42		$	1.47
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)	$	4.46		$	2.47
Statement of Cash Flows Data(b)
Additions to property, plant and equipment related to continuing operations	$	(1,974	)	$	(1,204	)	$	(3,485	)	$	(4,937	)	$	(4,170	)
Dividends paid	170			162			460			543			508
Dividends per share	$	0.20		$	0.20		$	0.68		$0.80			$0.72
Balance Sheet Data at December 31
Total assets	$	22,012		$	31,094		$	32,311		$	35,983		$	35,588
Total long-term debt, including capitalized leases	5,494			6,581			7,268			5,285			6,352

^(a)  Includes impairments to producing properties of $229 million, $67 million, $381 million, $132 million and $96 million in 2017, 2016, 2015, 2014 and 2013 and impairments to unproved properties of $246 million, $195 million, $655 million, $306 million and $572 million in 2017, 2016, 2015, 2014 and 2013 (see Item 8. Financial Statements and Supplementary Data – Note 10 to the consolidated financial statements). Includes a goodwill impairment of $340 million in 2015 related to the U.S. E&P reporting unit (see Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements).

^(b)  We closed on the sale of our Canada business in 2017 which resulted in an after-tax non-cash impairment charge of $4.96 billion and our Angola assets and Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements). The applicable periods have been recast to reflect as discontinued operations.

^(c)  December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and the other financial information found elsewhere in this Form 10-K. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See "Disclosures Regarding Forward-Looking Statements" (immediately prior to Part I) and Item 1A. Risk Factors.

Each of our segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

• International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.

Executive Summary

During 2017, we continued to strengthen our balance sheet, transform our portfolio and manage our capital and operating costs. Through multiple financing transactions in 2017, we have reduced total debt by approximately $1.75 billion which will result in a reduction to our future annual interest expense of approximately $115 million. Additionally, we closed on the sale of our Canadian business for approximately $2.5 billion and acquired acreage in the Permian basin, including over 70,000 net acres in Northern Delaware for approximately $1.9 billion.

As discussed in Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements, we closed on the sale of our Canadian business, which has been reflected as discontinued operations and is excluded from operations in all periods presented.

Key highlights include the following:

Liquidity and corporate financing

• Ended 2017 with liquidity of $4.0 billion, comprised of $563 million in cash and cash equivalents and an undrawn $3.4 billion revolving credit facility, which was increased from $3.3 billion in July 2017. Remaining proceeds of $750 million from the sale of our Canadian business are scheduled to be received in the first quarter of 2018.

• In third quarter 2017, we issued $1 billion of 4.4% senior unsecured notes due in 2027 and redeemed approximately $1.75 billion of debt due in 2017, 2018 and 2019. This offering and redemption reduced our future annual interest expense by approximately $64 million.

• In December 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction that preserved our ability to remarket up to $1 billion of tax-exempt municipal bonds prior to 2037. This redemption reduced our future annual interest expense by approximately $51 million.

Simplifying our portfolio

• We closed on the sale of our Canadian business for approximately $2.5 billion with over $1.8 billion in proceeds received to date and $750 million to be received in first quarter 2018.

• We closed on multiple Permian basin acquisitions for approximately $1.9 billion of cash on hand.

Financial and Operational results

• Total 2017 net sales volumes from continuing operations are 379 mboed, including Libya, which is 10% higher compared to 2016. This includes a 12% increase in sales volumes from the U.S resource plays to 217 mboed within our United States E&P segment.

• Due to improved cost structure and higher sales volumes, our production expense rate in our United States E&P segment decreased 7% to $5.57 per boe in 2017 compared to last year. In our International E&P segment, our production expense rate decreased 14% to $4.33 per boe in 2017 primarily due to an increase in sales volumes in E.G. and Libya.

• Added proved reserves of 193 mmboe for a reserve replacement ratio from continuing operations of 140%.

• Net cash provided by operating activities in 2017 was $2.0 billion, compared to $901 million in 2016 primarily as a result of improved price realizations, increased sales volumes and lower unit production expenses.

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• Our net loss per share from continuing operations was $0.97 in 2017 as compared to a net loss per share of $2.55 last year. Included in the 2017 net loss are:

◦ An increase in sales and other operating revenues of over 40% to $4.2 billion primarily due to improved price realizations and increased sales volumes.

◦ Our sales volumes from continuing operations increased 10% while production expense remained flat during 2017 as a result of improved cost structure.

◦ Depreciation, depletion and amortization expense increased 10% to $2.4 billion due to our increase in sales volumes from continuing operations.

◦ Exploration and impairment expenses increased by $248 million to $638 million, year over year, primarily due to non-cash impairment charges on proved and unproved properties primarily as a result of the anticipated sales of certain non-core international assets and due to lower forecasted long-term commodity prices.

◦ Our provision for income taxes was $376 million in 2017 primarily as a result of our full valuation allowance on our net federal deferred tax assets throughout 2017 and the effects of our foreign operations. See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion of the effects of U.S. Tax Reform Legislation.

Outlook

Capital Development Program

Our $2.3 billion2018 Capital Development Program will be over 90% allocated to our U.S. resource plays. Almost 60% of this development budget will be allocated to the high-return Eagle Ford and Bakken assets, which have demonstrated step-change performance improvements while operating at scale. Approximately one-third of the development budget will be allocated to our Northern Delaware and Oklahoma assets, where the majority of drilling activity will be transitioning to multi-well pads, while continuing strategic delineation and appraisal.

Our 2018 Capital Development Program is broken down by reportable operating segment in the table below:

(In millions)	Capital Development Program
United States E&P
Eagle Ford	$	710
Bakken	590
Oklahoma	410
Northern Delaware	380
Total United States E&P	$	2,090
International E&P and corporate other (a)	210
Total Capital Development Program	$	2,300

^(a) International E&P and corporate other includes our International E&P segment and other corporate items

Operations

Our net sales volumes from continuing operations, including Libya, averaged 379 mboed, 345 mboed and 385 mboed for 2017, 2016 and 2015, respectively. This 10% increase in 2017 was primarily due to new wells to sales in our U.S. resource plays, our acquisitions in Northern Delaware and the resumption of sales in Libya.

The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations section for a price-volume analysis for each of the segments.

Net Sales Volumes	2017	Increase (Decrease)		2016	Increase (Decrease)		2015
United States E&P (mboed)	234	5	%	223	(17	)%	269
International E&P (a)(mboed)	145	19	%	122	5	%	116
Total Continuing Operations (mboed)	379	10	%	345	(10	)%	385

^(a)     Years ended December 31, 2017, 2016 and 2015 include net sales volumes relating to Libya of 20 mboed, 3 mboed and none, respectively.

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United States E&P

The following tables provide additional detail regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:

Net Sales Volumes	2017	Increase (Decrease)	2016	Increase (Decrease)	2015
Equivalent Barrels (mboed)
Oklahoma	54	54%	35	40%	25
Eagle Ford	101	(4)%	105	(22)%	134
Bakken	56	4%	54	(8)%	59
Northern Delaware	6	100%	—	—%	—
Other United States(a)	17	(41)%	29	(43)%	51
Total United States E&P (mboed)	234	5%	223	(17)%	269

^(a) Year ended December 31, 2017 includes decreases of 14 mboed, consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood assets in West Texas and New Mexico in 2016. Year ended December 31, 2016 decreases relating to assets sold were 23 mboed, primarily consisting of Wyoming, West Texas, East Texas, North Louisiana and certain Gulf of Mexico assets. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.

Sales Mix - U.S. Resource Plays - 2017	Oklahoma	Eagle Ford	Bakken	Northern Delaware	Total
Crude oil and condensate	28%	58%	83%	66%	57%
Natural gas liquids	26%	21%	10%	8%	19%
Natural gas	46%	21%	7%	26%	24%

Drilling Activity - U.S. Resource Plays	2017	2016	2015
Gross Operated
Oklahoma:
Wells drilled to total depth	86	33	20
Wells brought to sales	73	28	21
Eagle Ford:
Wells drilled to total depth	182	168	251
Wells brought to sales	157	168	276
Bakken:
Wells drilled to total depth	90	3	35
Wells brought to sales	39	13	56
Northern Delaware
Wells drilled to total depth	27	—	—
Wells brought to sales	18	—	—

• Eagle Ford – Our net sales volumes were 101 mboed in 2017, 4% lower compared to 2016. We brought fewer wells to sales in 2017, while we increased well productivity through completion optimization and efficiency gains.

• Bakken – Our net sales volumes were 56 mboed in 2017 compared to 54 mboed in 2016. In 2017, we improved well performance with continued application of high intensity completions. During the year, we set a new record in the Williston Basin for the highest 30-day initial production oil rate.

• Oklahoma – Our net sales volumes in 2017 increased by 54% to 54 mboed compared to year ended 2016. Our activity during 2017 was concentrated in the STACK and was focused on leasehold capture, delineation drilling and infill spacing pilots.

• Northern Delaware – Our net sales volumes were 6 mboed in 2017 which reflected a partial year of production following the second quarter 2017 closing of the BC Operating and Black Mountain assets. During 2017 we focused our activity on delineation and leasehold capture across our position in Eddy and Lea Counties, New Mexico.

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International E&P

The following table provides net sales volumes from continuing operations within this segment:

Net Sales Volumes	2017	Increase (Decrease)	2016	Increase (Decrease)	2015
Equivalent Barrels (mboed)
Equatorial Guinea	109	7%	102	5%	97
United Kingdom(a)	14	(18)%	17	(11)%	19
Libya	20	567%	3	100%	—
Other International	2	100%	—	—%	—
Total International E&P (mboed)	145	19%	122	5%	116
Equity Method Investees
LNG (mtd)	6,423	9%	5,874	—%	5,884
Methanol (mtd)	1,374	1%	1,358	45%	937
Condensate & LPG (boed)	14,501	8%	13,430	10%	12,208

^(a)     Includes natural gas acquired for injection and subsequent resale.

• Equatorial Guinea – Net sales volumes in 2017 were higher than 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016 and lower volumes in first quarter 2016 due to a planned turnaround. Additionally, in April 2017 we received host government approval to develop Block D offshore E.G. through unitization with the Alba field.

• United Kingdom – Net sales volumes in 2017 decreased compared to 2016 primarily as a result of planned turn-around activity at the Brae and Foinaven complexes and the temporary shut-down of the outside-operated Forties Pipeline System during fourth quarter 2017.

• Libya – While civil and political unrest has interrupted operations in recent years, our production resumed in October 2016. During December 2016, liftings resumed from the Es Sider crude oil terminal. During 2017, sales volumes and production continued, except for a brief interruption in March 2017 due to civil unrest.

Market Conditions

Crude oil, natural gas and NGL benchmarks increased in 2017 as compared to the same period in 2016. As a result, we experienced increased price realizations associated with those benchmarks. We continue to expect crude oil, natural gas and NGLs benchmark prices to remain volatile based on global supply and demand, which will result in increases or decreases in our price realizations. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition – Critical Accounting Estimates for further discussion of how declines in commodity prices could impact us. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.

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United States E&P

 The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for 2017, 2016 and 2015:

	2017		Increase (Decrease)		2016		Increase (Decrease)		2015
Average Price Realizations (a)
Crude Oil and Condensate (per bbl)(b)		$49.35	28	%		$38.57	(11	)%	43.50
Natural Gas Liquids (per bbl)	20.55		56	%	13.15		(2	)%	13.37
Total Liquid Hydrocarbons (per bbl)	42.31		29	%	32.71		(14	)%	37.85
Natural Gas (per mcf) (c)	2.84		19	%	2.38		(11	)%	2.66
Benchmarks
WTI crude oil average of daily prices (per bbl)		$50.85	17	%		$43.47	(11	)%	48.76
LLS crude oil average of daily prices (per bbl)	54.04		20	%	45.02		(14	)%	52.33
Mont Belvieu NGLs (per bbl) (d)	23.76		37	%	17.40		3	%	16.94
Henry Hub natural gas settlement date average (per mmbtu)	3.11		26	%	2.46		(8	)%	2.66

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

^(b)  Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations per barrel by $0.75, $0.92, and $1.24 for 2017, 2016, and 2015.

^(c)  Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.

^(d)  Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.

Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.

Natural gas liquids – The majority of our NGLs volumes are sold at reference to Mont Belvieu prices.

Natural gas –A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  

International E&P

The following table presents our average price realizations and the related benchmark for crude oil for 2017, 2016 and 2015:

	2017		Increase (Decrease)		2016		(Decrease)		2015
Average Price Realizations
Crude Oil and Condensate (per bbl)		$53.05	27	%		$41.70	(12	)%		$47.50
Natural Gas Liquids (per bbl)	3.15		49	%	2.11		(25	)%	2.81
Total Liquid Hydrocarbons (per bbl)	43.36		35	%	32.10		(12	)%	36.67
Natural Gas (per mcf)	0.55		6	%	0.52		(24	)%	0.68
Benchmark
Brent (Europe) crude oil (per bbl)(a)		$54.25	25	%		$43.55	(17	)%		$52.35

^(a)  Average of monthly prices obtained from the United States Energy Information Agency website.

Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba Plant. The Alba Plant extracts NGLs and secondary condensate, which have been supplied under a long-term contract at a fixed price, leaving dry natural gas. The extracted NGLs and secondary condensate are sold by Alba Plant at market prices, with our share of its income/loss reflected in income from equity method investments, and the dry natural gas from Alba Plant is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and natural gas will not fully track market price movements. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. EGHoldings and AMPCO process the gas into LNG and methanol, which are sold at market prices, with our share of their income/loss reflected in the income from equity method investments line item on the Consolidated Statements of Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.

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Consolidated Results of Operations: 2017 compared to 2016

Sales and other operating revenues, including related partyare summarized by segment in the following table:

	Year Ended December 31,
(In millions)	2017			2016
Sales and other operating revenues, including related party
United States E&P	$	3,138		$	2,375
International E&P	1,154			665
Segment sales and other operating revenues, including related party	4,292			3,040
Unrealized gain (loss) on commodity derivative instruments	(81		)	(110		)
Sales and other operating revenues, including related party	$	4,211		$	2,930

Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

	Year Ended December 31,		Increase (Decrease) Related to				Year Ended December 31,
(In millions)	2016		Price Realizations		Net Sales Volumes		2017
United States E&P Price-Volume Analysis (a)
Liquid hydrocarbons	$	2,041	$	619	$	66	$	2,726
Natural gas	274		58		29		361
Realized gain on commodity
derivative instruments	44						45
Other sales	16						6
Total	$	2,375					$	3,138
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	546	$	264	$	205	$	1,015
Natural gas	87		4		6		97
Other sales	32						42
Total	$	665					$	1,154

^(a) Year ended December 31, 2016 includes sales volumes of 14 mboed on an annualized basis relating to assets sold when compared to 2017, primarily consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood assets in West Texas and New Mexico in 2016.

Marketing revenuesdecreased$78 million in 2017 from 2016, primarily as a result of lower marketed volumes in the United States E&P segment due to non-core asset dispositions. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period.

Income from equity method investments increased$81 million primarily due to higher price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement in net sales volumes primarily driven by the completion of the Alba field compression project in E.G. during the second half of 2016.

Net gain on disposal of assetsdecreased$331 million in 2017 from 2016. This decrease was primarily related to the sale of non-core assets in the first half of 2016 in Wyoming, West Texas and New Mexico, and the Gulf of Mexico. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.

Other income increased $25 million in 2017 from 2016. This increase was primarily a result of a downward revision in U.K. estimated asset retirement costs as well as timing of abandonment activities in the U.K. See Item 8. Financial Statements and Supplementary Data - Note 11 to the consolidated financial statements for detail about our asset retirement obligation.

Production expensesremained nearly flat during 2017 while our sales volumes from continuing operations increased. During 2017, our production expense rate (expense per boe) for United States E&P was lower primarily due to the disposition of higher cost non-core assets in Wyoming. The International E&P expense rate decreased in the year of 2017 primarily due to

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an increase in sales volumes in E.G. and Libya, combined with lower maintenance costs in E.G.

($ per boe)	2017		2016
Production Expense Rate
United States E&P		$5.57		$5.96
International E&P		$4.33		$5.05

Marketing expensesdecreased$77 million in 2017 from the prior year, consistent with the decrease in marketing revenues discussed above.

Other operating expenses decreased$53 million compared to 2016 which included the termination payment of our Gulf of Mexico deepwater drilling commitment in 2016.

Exploration expenses increased$86 million during 2017 versus the comparable 2016 period, due primarily to charges taken as a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our International E&P segment. In 2017, we recorded non-cash charges of $159 million comprised of $95 million in unproved property impairments in our International E&P segment and $64 million in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to exploration expenses of $43 million during 2017. Unproved property impairments during 2016 primarily consist of non-cash charges related to our decision to not drill our remaining Gulf of Mexico leases.

The following table summarizes the components of exploration expenses:

	Year Ended December 31,
(In millions)	2017		2016
Exploration Expenses
Unproved property impairments	$	246	$	195
Dry well costs	77		25
Geological and geophysical	25		5
Other	61		98
Total exploration expenses	$	409	$	323

Exploration expenses are also discussed in Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statements.

Depreciation, depletion and amortizationincreased$216 million in 2017 from the prior year primarily as a result of an increase of $176 million in the United States E&P due to a 5% increase in net sales volumes, and an increase in the DD&A rates within our U.S. resource plays. Also contributing to this higher expense was an increase of $52 million in our International E&P segment resulting from increased sales volumes due to the completion and start-up of our E.G. Alba field compression project in mid-2016, and the resumption of sales volumes and production in Libya. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The DD&A rate for United States E&P increased primarily due to the sales volume mix between our U.S. resource plays, and the outside-operated Gunflint field achieving first production in mid-2016. Also contributing to the increase was a reduction to the Eagle Ford proved developed reserve base in the fourth quarter of 2016. The DD&A rate for International E&P remained relatively consistent with the 2016 rate. The following table provides DD&A rates for each segment.

($ per boe)	2017		2016
DD&A rate
United States E&P		$23.51		$22.49
International E&P		$6.19		$6.21

Impairmentsincreased$162 million in 2017 from the comparable 2016 period. This increase was primarily consisting of $136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally, included in proved property impairments was $89 million in 2017 and $67 million in 2016, both relating to lower forecasted commodity prices in conventional properties in Oklahoma and the Gulf of Mexico.

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See Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statement for additional detail.

Taxes other than incomeincludes production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $32 million in the current year as a result of increased revenue and sales volumes, and due to a reserve being established for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:

	Year Ended December 31,
(In millions)	2017		2016
Taxes other than income
Production and severance	$	121	$	91
Ad valorem	13		23
Other	49		37
Total	$	183	$	151

General and administrative expenses decreased$81 million in 2017 primarily due to reduced pension settlement charges of $32 million in 2017 compared to $103 million in 2016.

Net interest and otherdecreased$62 million during 2017 primarily as a result of the termination of our forward starting interest rate swaps, which resulted in a gain of $47 million. Additionally, during 2017 we reduced total long term debt by approximately $1.75 billion which resulted in a reduction to our net interest and other. The components of net interest and other are detailed in Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements.

Loss on early extinguishment of debtincreased$51 million in 2017 primarily due to make-whole call provisions of $46 million paid upon the redemption of approximately $1.75 billion in senior unsecured notes. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for further detail.

Provision (benefit) for income taxesreflects an effective tax rate from continuing operations of 83% and 79% for 2017 and 2016. In 2017, our tax expense was primarily a result of our full valuation allowance on our net federal deferred tax assets throughout 2017 and the effects of our foreign operations.

See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion of the effective income tax rate.

Discontinued operations are presented net of tax. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for financial information concerning our discontinued operations.

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Segment Results: 2017 compared to 2016

Segment income(loss)

Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect comparability also are not allocated to operating segments.

The following table reconciles segment income (loss) to net income (loss):

	Year Ended December 31,
(In millions)	2017			2016
United States E&P	$	(148	)	$	(415	)
International E&P	374			228
Segment income (loss)	226			(187		)
Items not allocated to segments, net of income taxes (a)	(1,056		)	(1,900		)
Income (loss) from continuing operations	(830		)	(2,087		)
Income (loss) from discontinued operations (b)	(4,893		)	(53		)
Net income (loss)	$	(5,723	)	$	(2,140	)

^(a) See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for further detail about items not allocated to segments.

^(b) We sold our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.

 United States E&P segment lossdecreased$267 millionin 2017 compared to 2016 primarily due to higher price realizations and higher sales volumes. Partially offsetting this revenue increase was an increase in DD&A and a decrease in the income tax benefit, as we did not realize a tax benefit on any net federal deferred tax assets generated in 2017 due to the full valuation allowance on net federal deferred tax assets in the prior year.

International E&P segment incomeincreased$146 million in 2017 compared to 2016 primarily due to higher price realizations, and an increase in sales volumes in E.G. and Libya. This was partially offset by an increase in DD&A and income tax expense as a result of the increase in sales volumes.

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Consolidated Results of Operations: 2016 compared to 2015

Sales and other operating revenues, including related partyare summarized by segment in the following table:

	Year Ended December 31,
(In millions)	2016			2015
Sales and other operating revenues, including related party
United States E&P	$	2,375		$	3,358
International E&P	665			728
Segment sales and other operating revenues, including related party	3,040			4,086
Unrealized gain on crude oil derivative instruments	(110		)	50
Sales and other operating revenues, including related party	$	2,930		$	4,136

Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

	Year Ended December 31,		Increase (Decrease) Related to						Year Ended December 31,
(In millions)	2015		Price Realizations			Net Sales Volumes			2016
United States E&P Price-Volume Analysis
Liquid hydrocarbons	$	2,905	$	(321	)	$	(543	)	$	2,041
Natural gas	341		(32		)	(35		)	274
Realized gain on crude oil
derivative instruments	78								44
Other sales	34								16
Total	$	3,358							$	2,375
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	578	$	(78	)	$	46		$	546
Natural gas	108		(25		)	4			87
Other sales	42								32
Total	$	728							$	665

Marketing revenuesdecreased$259 million in 2016 from 2015. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are primarily related to lower marketed volumes in the United States, which were further compounded by a lower commodity price environment.

Income from equity method investmentsincreased$30 million primarily due to higher net sales volumes in the second half of 2016 in E.G. as a result of the completion of the Alba field compression project. Additionally, a partial impairment of our investment in an equity method investee in 2015 of $12 million contributed to the increase in the current year.

Net gain on disposal of assetsincreased$269 million in 2016 from 2015. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information about these dispositions.

Production expensesdecreased$267 million in 2016 from 2015. United States E&P declined$238 million primarily due to lower operational, maintenance and labor costs, coupled with lower net sales volumes resulting from the impact of our non-core asset dispositions and lower activity levels. International E&P declined$29 million largely due to lower operational and maintenance costs as well as a more favorable exchange rate on expenses.

The 2016 production expense rate (expense rate per boe) for United States E&P declined primarily due to cost reductions that occurred at a rate faster than our production decline. The International E&P expense rate decreased in 2016 primarily due to reduced maintenance and project costs in the U.K. and benefited from the favorable exchange rate. The following table provides production expense rates for each segment:

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($ per boe)	2016		2015
Production Expense Rate
United States E&P		$5.96		$7.38
International E&P		$5.05		$5.99

Marketing expensesdecreased$255 million in 2016 from the prior year, consistent with the decrease in marketing revenues discussed above.

Other operating expenses increased$74 million primarily as a result of the termination payment of our Gulf of Mexico deepwater drilling commitment.

Exploration expenses decreased$648 millionin 2016 compared to 2015, reflecting our strategic decision to transition out of conventional exploration. In 2016, unproved property impairments primarily consisted of non-cash charges related to our decision to not drill our remaining Gulf of Mexico leases and also included certain other unproved properties in the United States. In 2015, unproved property impairments are due to changes in our conventional exploration strategy (Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq), and the sale of certain properties in the Gulf of Mexico, as well as our unproved property in Colorado.

Dry well costs in 2015 included the operated Solomon exploration well in the Gulf of Mexico and our operated Sodalita West #1 exploratory well in E.G.

The following table summarizes the components of exploration expenses:

	Year Ended December 31,
(In millions)	2016		2015
Exploration Expenses
Unproved property impairments	$	195	$	655
Dry well costs	25		212
Geological and geophysical	5		31
Other	98		73
Total exploration expenses	$	323	$	971

Exploration expense are also discussed in Item 8. Financial Statements and Supplementary Data - Note 10 to the consolidated financial statements.

Depreciation, depletion and amortizationdecreased$565 million in 2016 from the prior year primarily as a result of net sales volume decreases in the United States E&P segment, including the impact of non-core asset dispositions, and volume declines due to base declines and lower completion activity. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for United States E&P decreased primarily due to a higher proved reserve base. The DD&A rate for International E&P declined primarily due to sales volume mix changes in E.G. and the U.K. for 2016.

($ per boe)	2016		2015
DD&A rate
United States E&P		$22.49		$24.24
International E&P		$6.21		$6.95

Impairmentsdecreased$654 million in 2016 versus 2015. Impairments in 2016 were primarily the result of lower forecasted commodity prices in conventional properties in Oklahoma and the Gulf of Mexico, and were also the result of revisions to estimated abandonment costs. Impairments in 2015 included $340 million for the goodwill impairment of the United States E&P reporting unit, and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma.

See Item 8. Financial Statements and Supplementary Data - Note 10 and Note 12 to the consolidated financial statement for additional detail.

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Taxes other than incomeincludes production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. The decline in revenue and sales volumes during 2016 resulted in a decline of $65 million compared to 2015. The following table summarizes the components of taxes other than income:

	Year Ended December 31,
(In millions)	2016		2015
Taxes other than income
Production and severance	$	91	$	131
Ad valorem	23		39
Other	37		46
Total taxes other than income	$	151	$	216

General and administrative expensesdecreased$107 million primarily due to cost savings realized from the 2015 workforce reductions including corresponding severance expenses.

Net interest and otherincreased$46 million primarily due to an increase in interest expense as a result of the increase in long-term debt in the second quarter of 2015. The components of net interest and other are detailed in Item 8. Financial Statements and Supplementary Data - Note 20 to the consolidated financial statements.

Provision (benefit) for income taxesreflects an effective tax rate of 79% and a benefit of 30% for 2016 and 2015. The increase in the 2016 effective tax rate was primarily due to the valuation allowance increase of $1,346 million related to our U.S. benefits on foreign taxes and other federal deferred taxes.

See Item 8. Financial Statements and Supplementary Data - Note 7 to the consolidated financial statements for a discussion of the effective income tax rate.

Discontinued operations are presented net of tax. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for financial information concerning our discontinued operations.

Segment Results: 2016 compared to 2015

Segment income (loss)

Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect comparability also are not allocated to operating segments

The following table reconciles segment income (loss) to net income (loss):

	Year Ended December 31,
(In millions)	2016			2015
United States E&P	$	(415	)	$	(452	)
International E&P	228			112
Segment income (loss)	(187		)	(340		)
Items not allocated to segments, net of income taxes (a)	(1,900		)	(1,361		)
Income (loss) from continuing operations	(2,087		)	(1,701		)
Income (loss) from discontinued operations (b)	(53		)	(503		)
Net income (loss)	$	(2,140	)	$	(2,204	)

^(a) See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for further detail about items not allocated to segments.

^(b) We sold our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.

 United States E&P segment lossdecreased$37 million in 2016 compared to 2015 as a result of lower DD&A expense, production costs, taxes other than income, and exploration expense, with these expense reductions more than offsetting the lower revenues as a result of decreases in both price realizations and net sales volumes.

International E&P segment incomeincreased$116 million in 2016 compared to 2015. The increase was largely due to lower exploration expenses in 2016, as our 2015 expense included costs relating to our transition out of our conventional exploration program. The remainder of the increase was due to lower production costs and DD&A as a result of lower asset retirement costs and sales mix, and an increase in income from equity method investments, partially offset by lower price realizations.

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Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity

Commodity prices are the most significant factor impacting our operating cash flows and the amount of capital available to reinvest into the business. In 2017, we experienced an increase in operating cash flows primarily due to improvements in the commodity price environment which resulted in an increase to consolidated average liquid hydrocarbons price realizations by over 30% to $42.59. Additionally, we closed on the sale of our Canadian business and other non-core assets resulting in net proceeds of $1.79 billion, which allowed us to be opportunistic with our high quality acquisitions in the Permian basin. Beyond the proceeds the non-core asset sales generated, the portfolio changes enhanced our profitability by disposing of higher unit cost operations and allowing for a more efficient allocation of our Capital Development Program to the higher return opportunities in the U.S. resource plays.

Steps taken in 2017 to continue our operating cash flow growth include the following actions:

• Improved cost structure by reducing production expense per boe in 2017.

◦United States E&P - 7%reduction to $5.57 per boe

◦International E&P - 14%reduction to $4.33 per boe

• Total 2017 net sales volumes from continuing operations increased 10% compared to 2016.

Other 2017 cash flow highlights include:

• Divested certain non-core assets resulting in net proceeds of $1.79 billion.

• We closed on multiple Permian basin acquisitions for $1.89 billion with cash on hand.

• Through multiple financing transactions we have reduced total debt by approximately $1.75 billion which will result in a reduction to our future annual interest expense of approximately $115 million.

• Expect to receive $750 million in remaining proceeds from the sale of our Canadian business by March 1, 2018.

• Expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion.

At December 31, 2017, we had approximately $4.0 billion of liquidity consisting of $563 million in cash and cash equivalents and $3.4 billion available under our revolving credit facility. As previously discussed in our Outlook section, we are targeting a $2.3 billion Capital Development Program for 2018. We believe our current liquidity level and balance sheet, along with our non-core asset disposition program and ability to access the capital markets provides us with the flexibility to fund our business throughout the different commodity price cycles. We will continue to evaluate the commodity price environment and our spending throughout 2018.

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Cash Flows

The following table presents sources and uses of cash and cash equivalents from continuing operations for 2017, 2016 and 2015:

	Year Ended December 31,
(In millions)	2017			2016			2015
Sources of cash and cash equivalents
Operating activities - continuing operations	$	1,988		$	901		$	1,537
Disposals of assets, net of cash transferred to the buyer	1,787			1,219			225
Common stock issuance	—			1,236			—
Borrowings	988			—			1,996
Other	68			56			101
Total sources of cash and cash equivalents	$	4,831		$	3,412		$	3,859
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(1,974	)	$	(1,204	)	$	(3,485	)
Acquisitions, net of cash acquired	(1,891		)	(902		)	—
Purchases of common stock	(11		)	(6		)	(11		)
Debt repayments	(2,764		)	(1		)	(1,069		)
Debt extinguishment costs	(46		)	—			—
Dividends paid	(170		)	(162		)	(460		)
Other	(30		)	(4		)	(8		)
Total uses of cash and cash equivalents	$	(6,886	)	$	(2,279	)	$	(5,033	)

Cash flows generated from operating activities in 2017 were higher as commodity prices and price realizations improved compared to 2016. This increase in price realization coupled with our increased sales volumes and continued focus on cost reductions resulted in an increase to cash flows generated from operating activities.

Proceeds from the disposals of assets for 2017 are primarily a result of the disposal of our Canadian business, and proceeds from disposals of assets in 2016 are primarily from the sale of our Wyoming upstream and midstream assets, as well as the sale of certain other non-operated CO2 and waterflood assets in West Texas and New Mexico. Disposals of assets in 2015 pertain to the sale of certain of our operated and non-operated producing properties in the Gulf of Mexico as well as natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma. Disposition transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements.

Issuance of common stock reflects net proceeds received in March 2016 from our public sale of common stock. See Item 8. Financial Statements and Supplementary Data - Note 22 to the consolidated financial statements for additional information.

Borrowings in 2017 are a result of the issuance of $1 billion of 4.4% senior unsecured notes due in 2027. Our 2015 borrowings reflect net proceeds received from the issuance of senior notes in June 2015. Financing transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for additional information.

Additions to property, plant and equipment reflect a significant use of cash and cash equivalents. The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows for 2017, 2016 and 2015:

	Year Ended December 31,
(In millions)	2017			2016		2015
United States E&P	$	2,081		$	936	$	2,553
International E&P	42			82		368
Corporate	27			18		25
Total capital expenditures	2,150			1,036		2,946
Change in capital expenditure accrual	(176		)	168		539
Additions to property, plant and equipment	$	1,974		$	1,204	$	3,485

During 2017, we closed on multiple Permian basin acquisitions for approximately $1.9 billion with cash on hand. Additionally, during 2016, we closed the Oklahoma STACK acquisition for a purchase price of $902 million, net of cash

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acquired; see Item 8. Financial Statements and Supplementary Data – Note 4 to the consolidated financial statements for further information concerning acquisitions.

In December 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction. Additionally, during the third quarter of 2017, we used the net proceeds of the borrowing disclosed above plus existing cash on hand to redeem $1.76 billion in senior unsecured notes resulting in a recognized loss on early extinguishment of debt of $46 million, primarily due to make-whole call provisions. In November 2015, we repaid our $1 billion 0.90% senior notes upon maturity. Financing transactions are discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for additional information.

During 2017, the Board of Directors approved a $0.05 per share quarterly dividend. See Capital Requirements below for additional information about the fourth quarter dividend. During 2015 we announced an adjustment to our quarterly dividend starting in third quarter 2015, with the full-year impact resulting in a decrease of dividends paid in 2017 and 2016.

Liquidity and Capital Resources

In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020, to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving credit facility. At December 31, 2017, we had approximately $4.0 billion of liquidity consisting of $563 million in cash and cash equivalents and $3.4 billion available under our revolving credit facility. During the first quarter of 2018, we expect to receive $750 million in remaining proceeds from the sale of our Canadian business. Our working capital requirements are supported by these sources and we may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets. Our corporate credit ratings as of December 31, 2017 are: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (stable). A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors for a discussion of how a downgrade in our credit ratings could affect us.

In December of 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction that preserved our ability to remarket up to $1 billion of tax-exempt municipal bonds prior to 2037. We may incur additional debt in order to fund our capital expenditures, acquisitions or development activities, or for general corporate or other purposes. A higher level of indebtedness could increase the risk that our liquidity and financial flexibility deteriorates. See Item 1A. Risk Factors for a further discussion of how our level of indebtedness could affect us.

Capital Resources

Credit Arrangements and Borrowings

At December 31, 2017, we had no borrowings against our revolving credit facility.

At December 31, 2017, we had $5.5 billion in long-term debt outstanding, with our next debt maturity in the amount of $600 million due in 2020.

We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

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Asset Disposals

We closed on $1.8 billion of non-core asset sales during 2017, with the largest transaction being the disposal of our Canadian business. During the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. We have closed on one of these agreements in 2017, and we expect the remainder of the agreements to close during 2018.

See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional discussion of these dispositions.    

Debt-To-Capital Ratio

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. Our debt-to-capital ratio was 32% at December 31, 2017 and 29% at December 31, 2016.

(Dollars in millions)	2017			2016
Long-term debt due within one year	$	—		$	686
Long-term debt	5,494			6,581
Total debt	$	5,494		$	7,267
Equity	$	11,708		$	17,541
Calculation
Total debt	$	5,494		$	7,267
Total debt plus equity (total capitalization)	$	17,202		$	24,808
Debt-to-capital ratio	32		%	29		%

Capital Requirements

Capital Spending

Our approved Capital Development Program for 2018 is $2.3 billion. Additional details were previously discussed in Outlook.

Share Repurchase Program

The remaining share repurchase authorization as of December 31, 2017 is $1.5 billion.

Other Expected Cash Outflows

On January 30, 2018, our Board of Directors approved a dividend of $0.05 per share for the fourth quarter of 2017. The dividend is payable on March 12, 2018 to shareholders on record on February 21, 2018.

We plan to make contributions of up to $65 million to our funded pension plans during 2018. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $21 million in 2018.

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Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2017.

(In millions)	Total		2018		2019- 2020		2021- 2022		Later Years
Short and long-term debt (includes interest)(a)	$	8,776	$	256	$	1,103	$	1,512	$	5,905
Lease obligations	119		29		55		31		4
Purchase obligations:
Oil and gas activities(b)	108		94		8		4		2
Service and materials contracts(c)	115		65		48		2		—
Transportation and related contracts	1,581		313		483		241		544
Drilling rigs and fracturing crews(d)	21		21		—		—		—
Other	42		13		24		5		—
Total purchase obligations	1,867		506		563		252		546
Other long-term liabilities reported in the consolidated balance sheet(e)	486		141		77		63		205
Total contractual cash obligations(f)	$	11,248	$	932	$	1,798	$	1,858	$	6,660

^(a)  Includes anticipated cash payments for interest of $256 million for 2018, $503 million for 2019-2020, $477 million for 2021-2022 and $2,003 million for the remaining years for a total of $3,239 million.

^(b)  Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.

^(c)  Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

^(d)  Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31, 2017 our minimum commitment would be $14 million.

^(e)  Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2027. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

^(f)  This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,483 million. See Item 8. Financial Statements and Supplementary Data – Note 11 to the consolidated financial statements.

Transactions with Related Parties

We own a 63% working interest in the Alba field offshore E.G. Onshore E.G., we own a 52% interest in an LPG processing plant, a 60% interest in an LNG production facility and a 45% interest in a methanol production plant, each through equity method investees. We sell our natural gas from the Alba field to these equity method investees as the feedstock for their production processes.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the U.S. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

We will issue stand-alone letters of credit when required by a business partner. Such letters of credit outstanding at December 31, 2017, 2016 and 2015 aggregated $89 million, $166 million and $53 million. Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet. For example, they are issued to counterparties to support firm transportation agreements and future abandonment liabilities.

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Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies

We have incurred and may continue to incur substantial capital, operating and maintenance and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.

New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We strive to comply with all legal requirements regarding the environment, but as not all costs are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Environmental, Health and Safety Matters, Item 1A. Risk Factors and Item 3. Legal Proceedings.

Critical Accounting Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

Estimated Quantities of Net Reserves

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil and condensate, NGLs and natural gas reserves. The amount of estimated proved reserve volumes affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. In addition, the expected future cash flows to be generated by producing properties are used for testing impairment and the expected future taxable income available to realize deferred tax assets, also in part, rely on estimates of quantities of net reserves. Refer to the applicable sections below for further discussion of these accounting estimates.

The estimation of quantities of net reserves is a highly technical process performed by our engineers and geoscientists for crude oil and condensate, NGLs and natural gas, which is based upon several underlying assumptions. The reserve estimates may change as additional information becomes available and as contractual, operational, economic and political conditions change. We evaluate our reserves using drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves. The data for a given reservoir may also change over time as a result of numerous factors including, but not limited to, additional development activity, production history and continual reassessment of the viability of production under varying economic conditions.

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Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC. The table below provides the 2017 SEC pricing for certain benchmark prices:

	SEC Pricing 2017
WTI Crude oil (per bbl)	$	51.34
Henry Hub natural gas (per mmbtu)	$	2.98
Brent crude oil (per bbl)	$	54.39
Mont Belvieu NGLs (per bbl)	$	22.03

When determining the December 31, 2017 proved reserves for each property, the benchmark prices listed above were adjusted using price differentials that account for property-specific quality and location differences.

Estimates of future cash flows associated with proved reserves are based on actual costs of developing and producing proved reserves at the end of the year. If commodity prices were to decrease by approximately 10%, below average prices used to estimate 2017 proved reserves (see table above), we would not expect price related reserve revisions to have a material impact on proved reserve volumes. For further discussion of risks associated with our estimation of proved reserves, see Part I. Item 1A Risk Factors.

Depreciation and depletion of crude oil and condensate, NGLs and natural gas producing properties is determined by the units-of-production method and could change with revisions to estimated proved reserves. While revisions of previous reserve estimates have not historically been significant to the depreciation and depletion rates of our segments, any reduction in proved reserves, could result in an acceleration of future DD&A expense. The following table illustrates, on average, the sensitivity of each segment's units-of-production DD&A per boe and pretax income to a hypothetical 10% change in 2017 proved reserves based on 2017 production.

	Impact of a 10% Increase in Proved Reserves					Impact of a 10% Decrease in Proved Reserves
(In millions, except per boe)	DD&A per boe			Pretax Income		DD&A per boe		Pretax Income
United States E&P	$	(2.14	)	$	183	$	2.61	$	(224	)
International E&P	$	(0.56	)	$	30	$	0.69	$	(36	)

Asset Retirement Obligations

We have material legal, regulatory and contractual obligations to remove and dismantle long-lived assets and to restore land or seabed at the end of oil and gas production operations. A liability equal to the fair value of such obligations and a corresponding capitalized asset retirement cost are recognized on the balance sheet in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be made. The capitalized asset retirement cost is depreciated using the units-of-production method or the straight line method (dependent on the underlying asset) and the discounted liability is accreted over the period until the obligation is satisfied, the impacts of which are recognized as DD&A in the consolidated statements of income. In many cases, the satisfaction and subsequent discharge of these liabilities is projected to occur many years, or even decades, into the future. Furthermore, the legal, regulatory and contractual requirements often do not provide specific guidance regarding removal practices and the criteria that must be fulfilled when the removal and/or restoration event actually occurs.

Estimates of retirement costs are developed for each property based on numerous factors, such as the scope of the dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Changes in estimated asset retirement obligations for late life assets could result in future impairment charges or in the recognition of income. See Item 8. Financial Statements and Supplementary Data – Note 11 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates.

An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of obligations that must be assessed, the number of underlying assumptions and the wide range of possible assumptions.

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Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Item 8. Financial Statements and Supplementary Data – Note 14 to the consolidated financial statements for disclosures regarding our fair value measurements.

Significant uses of fair value measurements include:

• impairment assessments of long-lived assets;

• impairment assessments of goodwill; and

• recorded value of derivative instruments.

The need to test long-lived assets and goodwill for impairment can be based on several indicators, including a significant reduction in prices of crude oil and condensate, NGLs and natural gas, sustained declines in our common stock, reductions to our Capital Development Program, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which the property is located.

Impairment Assessments of Long-Lived Assets

Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of an impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value. During 2017 lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment triggered an assessment of certain of our long-lived assets related to oil and gas producing properties for impairment. We estimated the fair values using an income and market approach and recognized impairments. As of December 31, 2017 our estimated undiscounted cash flows relating to our remaining long-lived assets significantly exceeded their carrying values. Long-lived assets most at risk for future impairment had estimated undiscounted cash flows that exceeded their $66 million carrying value by $22 million. See Item 8. Financial Statements and Supplementary Data Note 10 and Note 14 to the consolidated financial statements for discussion of impairments recorded in 2017, 2016 and 2015 and the related fair value measurements.

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Fair value calculated for the purpose of testing our long-lived assets for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:

• Future crude oil and condensate, NGLs and natural gas prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices.

• Estimated quantities of crude oil and condensate, NGLs and natural gas. Such quantities are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.

• Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.

• Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.

• Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset by lower costs.

Impairment Assessments of Goodwill

Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We performed our annual impairment test in the second quarter of 2017 for the International E&P reporting unit and no impairment was required. As of the date of our last goodwill impairment assessment, our International E&P reporting unit fair value exceeded its book value by over 40%.

We estimate the fair values of our International E&P reporting unit using a combination of market and income approaches. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilizes discounted cash flows, which are based on forecasted assumptions. Key assumptions to the income approach are the same as those described above regarding our impairment assessment of long lived assets and are consistent with those that management uses to make business decisions. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in such assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. See Item 8. Financial Statements and Supplementary Data Note 12 to the consolidated financial statements for additional discussion of goodwill.

Derivatives

We record all derivative instruments at fair value. Fair value measurements for all our derivative instruments are based on observable market-based inputs that are corroborated by market data and are discussed in Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

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Income Taxes

We are subject to income taxes in numerous taxing jurisdictions worldwide. Estimates of income taxes to be recorded involve interpretation of complex tax laws and assessment of the effects of foreign taxes on our U.S. federal income taxes.

Uncertainty exists regarding tax positions taken in previously filed tax returns which remain subject to examination, along with positions expected to be taken in future returns. We provide for unrecognized tax benefits, based on the technical merits, when it is more likely than not that an uncertain tax position will not be sustained upon examination. Adjustments are made to the uncertain tax positions when facts and circumstances change, such as the closing of a tax audit; court proceedings; changes in applicable tax laws, including tax case rulings and legislative guidance; or expiration of the applicable statute of limitations.

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act ("Tax Reform Legislation"), which made significant changes to U.S. federal income tax law. We expect that certain aspects of the Tax Reform Legislation will positively impact our future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate. The Tax Reform Legislation is a comprehensive bill containing several other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to have a material effect on our results. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. Item 8. Financial Statements and Supplementary Data – Note 7 to the consolidated financial statements for further disclosure regarding Tax Reform Legislation.

We have recorded deferred tax assets and liabilities, measured at enacted tax rates, for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. In accordance with U.S. GAAP accounting standards, we routinely assess the realizability of our deferred tax assets and reduce such assets, to the expected realizable amount, by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the forecasts of future income (loss) in the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on objectivity.

We base our future taxable income estimates on projected financial information which we believe to be reasonably likely to occur. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes. Future operating conditions can be affected by numerous factors, including (i) future crude oil and condensate, NGLs and natural gas prices, (ii) estimated quantities of crude oil and condensate, NGLs and natural gas, (iii) expected timing of production, and (iv) future capital requirements. These assumptions are described in further detail above regarding our impairment assessment of long-lived assets. An estimate of the sensitivity to changes in assumptions resulting in future taxable income calculations is not practicable, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures.

Based on the assumptions and judgments described above, as of December 31, 2017, we reflect a valuation allowance in our Consolidated Balance Sheet of $926 million against our gross deferred tax assets of $2.0 billion in various jurisdictions in which we operate. Our gross deferred tax assets consist primarily of federal U.S. operating loss carryforwards of $898 million, which will expire in 2035, 2036 and 2037. Since December 31, 2016, we have maintained a full valuation allowance on our net federal deferred tax assets. If objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as forecasted projections of taxable income in future years, we would adjust the amount of the federal deferred tax assets considered realizable and reduce the provision for income taxes in the period of adjustment.

Pension and Other Postretirement Benefit Obligations

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:

• the discount rate for measuring the present value of future plan obligations;

• the expected long-term return on plan assets;

• the rate of future increases in compensation levels; and

• health care cost projections.

We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our U.S. pension plans and our other U.S. postretirement benefit plans due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a

49

review of market yields on high-quality corporate debt and use of our third-party actuary's discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a recognized rating agency, only non-callable bonds are included and outlier bonds (bonds that have a yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is required to have at least $250 million par value outstanding. The constructed yield curve is based on those bonds representing the 50% highest yielding issuances within each defined maturity group.

Of the assumptions used to measure obligations and estimated annual net periodic benefit cost as of December 31, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. The hypothetical impacts of a 0.25% change in the discount rates of 3.55% for our U.S. pension plans and 3.54% for our other U.S. postretirement benefit plans is summarized in the table below:

	Impact of a 0.25% Increase in Discount Rate					Impact of a 0.25% Decrease in Discount Rate
(In millions)	Obligation			Expense		Obligation		Expense
U.S. pension plans	$	(4	)	$	—	$	4	$	—
Other U.S. postretirement benefit plans	$	(5	)	$	—	$	5	$	—

The asset rate of return assumption for the funded U.S. plan considers the plan's asset mix (currently targeted at approximately 55% equity and 45% other fixed income securities), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Decreasing the 6.50% asset rate of return assumption by 0.25% would not have a significant impact on our defined benefit pension expense.

Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans. Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.

Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the consolidated balance sheets.

Contingent Liabilities

We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, as well as tax disputes and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances outside legal counsel is utilized.

We generally record losses related to these types of contingencies as other operating expense or general and administrative expense in the consolidated statements of income, except for tax contingencies unrelated to income taxes, which are recorded as taxes other than income. For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.

Accounting Standards Not Yet Adopted

See Item 8. Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks related to the volatility of crude oil and condensate, NGLs, and natural gas prices as the volatility of these prices continues to impact our industry. We expect commodity prices to remain volatile and unpredictable in the future. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations. We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction. While the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.

See Item 8. Financial Statements and Supplementary Data – Notes 13 and 14 to the consolidated financial statements for more information about the fair value measurement of our derivatives, the amounts recorded in our consolidated balance sheets and statements of income and the related notional amounts.

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. However, management will periodically protect prices on forecasted sales to support cash flow and liquidity, as deemed appropriate. We may use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our business. Our consolidated results for 2017 and 2016 were impacted by crude oil and natural gas derivatives related to a portion of our forecasted United States E&P sales. The table below provides a summary of open positions as of December 31, 2017 and the weighted average price for those contracts:

Crude Oil
	2018				2019
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars (a)
Volume (Bbls/day)	85,000	85,000	85,000	85,000	10,000	10,000
Weighted average price per Bbl:
Ceiling	$56.38	$56.38	$56.96	$56.96	$60.00	$60.00
Floor	$51.65	$51.65	$51.53	$51.53	$55.00	$55.00
Sold put	$45.00	$45.00	$44.65	$44.65	$47.00	$47.00
Swaps
Volume (Bbls/day)	20,000	20,000	—	—	—	—
Weighted average price per Bbl	$55.12	$55.12	$—	$—	$—	$—
Basis Swaps (b)
Volume (Bbls/day)	5,000	5,000	10,000	10,000	—	—
Weighted average price per Bbl	$(0.60)	$(0.60)	$(0.67)	$(0.67)	$—	$—

^(a)  Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling

price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.

^(b)  The basis differential price is between WTI Midland and WTI Cushing.

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Natural Gas
	2018
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	200,000	160,000	160,000	160,000
Weighted average price per MMBtu
Ceiling	$3.79	$3.61	$3.61	$3.61
Floor	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.50	$2.50	$2.50

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of December 31, 2017:

(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Crude oil derivatives	$	(180	)	$	149
Natural gas derivatives	(8		)	7
Total	$	(188	)	$	156

Interest Rate Risk

At December 31, 2017, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Our sensitivity to interest rate movements and corresponding changes in the fair value of our fixed rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value. Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on our financial assets and liabilities as of December 31, 2017, is provided in the following table.

(In millions)	Fair Value				Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%
Financial assets (liabilities): (a)
Long-term debt, including amounts due within one year	$	(5,976	)	(b)(c)	$	190	$	(202	)

^(a)  Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.

^(b)  Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

^(c)  Excludes capital leases.

Counterparty Risk

We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices fall below current levels, some of our counterparties may experience liquidity problems and may not be able to meet their financial obligations to us. We review the creditworthiness of counterparties and use master netting agreements when appropriate.

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Item 8. Financial Statements and Supplementary Data

Index

	Page
Management’s Responsibilities for Financial Statements	54
Management’s Report on Internal Control over Financial Reporting	54
Report of Independent Registered Public Accounting Firm	55
Audited Consolidated Financial Statements
Consolidated Statements of Income	57
Consolidated Statements of Comprehensive Income	58
Consolidated Balance Sheets	59
Consolidated Statements of Cash Flows	60
Consolidated Statements of Stockholders’ Equity	61
Notes to Consolidated Financial Statements	62
Select Quarterly Financial Data (Unaudited)	98
Supplementary Information on Oil and Gas Producing Activities (Unaudited)	99

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Management’s Responsibilities for Financial Statements

To the Stockholders of Marathon Oil Corporation:

The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries ("Marathon Oil") are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.

Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.

The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.

/s/ Lee M. Tillman	/s/ Dane E. Whitehead
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

Management’s Report on Internal Control over Financial Reporting

To the Stockholders of Marathon Oil Corporation:

Marathon Oil’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13(a) – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

An evaluation of the design and effectiveness of our internal control over financial reporting, based on the 2013 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon Oil’s management concluded that its internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2017 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/s/ Lee M. Tillman	/s/ Dane E. Whitehead
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

54

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Marathon Oil Corporation:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Marathon Oil Corporation and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of income, comprehensive income, cash flows and stockholders’ equity for each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 22, 2018

We have served as the Company’s auditor since 1982.

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MARATHON OIL CORPORATION

Consolidated Statements of Income

	Year Ended December 31,
(In millions, except per share data)	2017			2016			2015
Revenues and other income:
Sales and other operating revenues, including related party	$	4,211		$	2,930		$	4,136
Marketing revenues	162			240			499
Income from equity method investments	256			175			145
Net gain (loss) on disposal of assets	58			389			120
Other income	78			53			53
Total revenues and other income	4,765			3,787			4,953
Costs and expenses:
Production	706			712			979
Marketing, including purchases from related parties	168			245			500
Other operating	431			484			410
Exploration	409			323			971
Depreciation, depletion and amortization	2,372			2,156			2,721
Impairments	229			67			721
Taxes other than income	183			151			216
General and administrative	400			481			588
Total costs and expenses	4,898			4,619			7,106
Income (loss) from operations	(133		)	(832		)	(2,153		)
Net interest and other	(270		)	(332		)	(286		)
Loss on early extinguishment of debt	(51		)	—			—
Income (loss) from continuing operations before income taxes	(454		)	(1,164		)	(2,439		)
Provision (benefit) for income taxes	376			923			(738		)
Income (loss) from continuing operations	(830		)	(2,087		)	(1,701		)
Income (loss) from discontinued operations	(4,893		)	(53		)	(503		)
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Per Share Data
Basic:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)
Diluted:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)
Dividends	$	0.20		$	0.20		$	0.68
Weighted average shares:
Basic	850			819			677
Diluted	850			819			677

The accompanying notes are an integral part of these consolidated financial statements.

57

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income

	Year Ended December 31,
(In millions)	2017			2016			2015
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	21			16			228
Income tax provision (benefit)	7			(4		)	(86		)
Postretirement and postemployment plans, net of tax	28			12			142
Derivative hedges
Net unrecognized gain (loss)	(13		)	61			—
Reclassification of gains on terminated derivative hedges	(47		)	—			—
Income tax provision (benefit)	21			(22		)	—
Derivative hedges, net of tax	(39		)	39			—
Foreign currency hedges
Net recognized loss reclassified to discontinued operations	34			—			—
Income tax provision (benefit)	(4		)	—			—
Foreign currency hedges, net of tax	30			—			—
Other, net of tax	2			1			—
Other comprehensive income (loss)	21			52			142
Comprehensive income (loss)	$	(5,702	)	$	(2,088	)	$	(2,062	)

The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION

Consolidated Balance Sheets

	December 31,
(In millions, except par values and share amounts)	2017			2016
Assets
Current assets:
Cash and cash equivalents	$	563		$	2,488
Receivables, less reserve of $12 and $6	1,082			748
Notes receivable	748			—
Inventories	126			136
Other current assets	36			66
Current assets held for sale	11			227
Total current assets	2,566			3,665
Equity method investments	847			931
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,564 and $20,255	17,665			16,727
Goodwill	115			115
Other noncurrent assets	764			558
Noncurrent assets held for sale	55			9,098
Total assets	$	22,012		$	31,094
Liabilities
Current liabilities:
Accounts payable	$	1,395		$	967
Payroll and benefits payable	108			129
Accrued taxes	177			94
Other current liabilities	288			243
Long-term debt due within one year	—			686
Current liabilities held for sale	—			121
Total current liabilities	1,968			2,240
Long-term debt	5,494			6,581
Deferred tax liabilities	833			769
Defined benefit postretirement plan obligations	362			345
Asset retirement obligations	1,428			1,602
Deferred credits and other liabilities	217			225
Noncurrent liabilities held for sale	2			1,791
Total liabilities	10,304			13,553
Commitments and contingencies
Stockholders’ Equity
Preferred stock - no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 937 million and 937 million shares, respectively (par value $1 per share, 1.1 billion shares authorized)	937			937
Held in treasury, at cost – 87 million and 90 million shares	(3,325		)	(3,431		)
Additional paid-in capital	7,379			7,446
Retained earnings	6,779			12,672
Accumulated other comprehensive loss	(62		)	(83		)
Total stockholders' equity	11,708			17,541
Total liabilities and stockholders' equity	$	22,012		$	31,094

The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows

	Year Ended December 31,
(In millions)	2017			2016			2015
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	4,893			53			503
Depreciation, depletion and amortization	2,372			2,156			2,721
Impairments	229			67			721
Exploratory dry well costs and unproved property impairments	323			220			867
Net (gain) loss on disposal of assets	(58		)	(389		)	(120		)
Deferred income taxes	(61		)	828			(804		)
Net (gain) loss on derivative instruments	(11		)	63			(126		)
Net cash received (paid) in settlement of derivative instruments	98			61			55
Stock based compensation	50			48			45
Equity method investments, net	20			17			33
Changes in:
Current receivables	(334		)	67			790
Inventories	10			64			25
Current accounts payable and accrued liabilities	297			(137		)	(906		)
All other operating, net	(117		)	(77		)	(63		)
Net cash provided by operating activities from continuing operations	1,988			901			1,537
Investing activities:
Additions to property, plant and equipment	(1,974		)	(1,204		)	(3,485		)
Acquisitions, net of cash acquired	(1,891		)	(902		)	—
Disposal of assets, net of cash transferred to the buyer	1,787			1,219			225
Equity method investments - return of capital	64			55			77
Purchases of short term investments	—			—			(925		)
Maturities of short term investments	—			—			925
All other investing, net	(30		)	(1		)	24
Net cash used in investing activities from continuing operations	(2,044		)	(833		)	(3,159		)
Financing activities:
Borrowings	988			—			1,996
Debt repayments	(2,764		)	(1		)	(1,069		)
Debt extinguishment costs	(46		)	—			—
Common stock issuance	—			1,236			—
Purchases of common stock	(11		)	(6		)	(11		)
Dividends paid	(170		)	(162		)	(460		)
All other financing, net	—			1			(5		)
Net cash provided by (used in) financing activities	(2,003		)	1,068			451
Cash Flow from Discontinued Operations:
Operating activities	141			177			39
Investing activities	(13		)	(41		)	(43		)
Changes in cash included in current assets held for sale	2			100			90
Net increase in cash and cash equivalents of discontinued operations	130			236			86
Effect of exchange rate changes on cash and cash equivalents:	4			(3		)	(3		)
Net increase (decrease) in cash and cash equivalents	(1,925		)	1,369			(1,088		)
Cash and cash equivalents at beginning of period	2,488			1,119			2,207
Cash and cash equivalents at end of period	$	563		$	2,488		$	1,119

The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity

	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Total Equity
December 31, 2014 Balance	$	—	$	770	$	(3,642	)	$	6,531		$	17,638		$	(277	)	$	21,020
Shares issued - stock-based
compensation	—		—		96			(32		)	—			—			64
Shares repurchased	—		—		(8		)	—			—			—			(8		)
Stock-based compensation	—		—		—			(1		)	—			—			(1		)
Net loss	—		—		—			—			(2,204		)	—			(2,204		)
Other comprehensive loss	—		—		—			—			—			142			142
Dividends paid	—		—		—			—			(460		)	—			(460		)
December 31, 2015 Balance	$	—	$	770	$	(3,554	)	$	6,498		$	14,974		$	(135	)	$	18,553
Shares issued - stock-based
compensation	—		—		128			(86		)	—			—			42
Shares repurchased	—		—		(5		)	—			—			—			(5		)
Stock-based compensation	—		—		—			(35		)	—			—			(35		)
Net loss	—		—		—			—			(2,140		)	—			(2,140		)
Other comprehensive income	—		—		—			—			—			52			52
Dividends paid	—		—		—			—			(162		)	—			(162		)
Common stock issuance	—		167		—			1,069			—			—			1,236
December 31, 2016 Balance	$	—	$	937	$	(3,431	)	$	7,446		$	12,672		$	(83	)	$	17,541
Shares issued - stock-based
compensation	—		—		117			(50		)	—			—			67
Shares repurchased	—		—		(11		)	—			—			—			(11		)
Stock-based compensation	—		—		—			(17		)	—			—			(17		)
Net loss	—		—		—			—			(5,723		)	—			(5,723		)
Other comprehensive income	—		—		—			—			—			21			21
Dividends paid	—		—		—			—			(170		)	—			(170		)
Common stock issuance	—		—		—			—			—			—			—
December 31, 2017 Balance	$	—	$	937	$	(3,325	)	$	7,379		$	6,779		$	(62	)	$	11,708
(Shares in millions)	Preferred Stock		Common Stock		Treasury Stock
December 31, 2014 Balance	—		770		95
Shares issued - stock-based
compensation	—		—		(2		)
Shares repurchased	—		—		—
December 31, 2015 Balance	—		770		93
Shares issued - stock-based
compensation	—		—		(3		)
Shares repurchased	—		—		—
Common stock issuance	—		167		—
December 31, 2016 Balance	—		937		90
Shares issued - stock-based
compensation	—		—		(3		)
Shares repurchased	—		—		—
Common stock issuance	—		—		—
December 31, 2017 Balance	—		937		87

The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

1. Summary of Principal Accounting Policies

We are a global energy company engaged in exploration, production and marketing of crude oil and condensate, NGLs and natural gas; as well as production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.

Basis of presentation and principles applied in consolidation – These consolidated financial statements include the accounts of our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments– Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Reclassifications – We have reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.

Discontinued operations – As a result of the sale of our Canadian business in 2017, we reflected this business as discontinued operations in all periods presented. Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Assets and liabilities are presented as held for sale in the historical periods in the consolidated balance sheets. See Note 5 for discussion of the divestiture in further detail.

As discussed above we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases in the second quarter 2017. The characteristics and composition of our North America E&P reporting segment remained unchanged and there was no effect on previously reported segment information. As all our remaining properties within the segment are located within the United States, we concluded that our North America E&P segment would be renamed United States E&P segment, effective June 30, 2017. During the year, no changes occurred to our International E&P segment. See Note 6 for further information on our reportable segments.

Use of estimates – The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Supplementary Data - Supplementary Information on Oil and gas Producing Activities for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, goodwill, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of crude oil and condensate, NGLs and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Short-term Investments - Our short-term investments are comprised of bank time deposits with original maturities of greater than three months but less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost.

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. We routinely assess the collectability of receivable balances to determine if the amount of the reserve in allowance for doubtful accounts is sufficient.

Notes receivable - We hold two notes receivable from the sale of our Canadian business, which closed in the second quarter of 2017. Both notes receivable were initially recorded at fair value and are reported at amortized cost. The notes receivable are evaluated for collectability on an individual basis each reporting period, based on the financial condition of the debtor. No allowances for credit losses were established for the notes receivable as of December 31, 2017. See Note 5 for additional discussion.

Inventories – Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, commodity locational risk, foreign currency risk and interest rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities. Our derivative instruments contain no significant contingent credit features.

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Cash flow hedges – We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. Derivative instruments designated as cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The effective portion of changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged item is reclassified to net income when the underlying forecasted transaction is recognized in net income. Ineffective portions of a cash flow hedge’s change in fair value are recognized currently within net interest and other on the consolidated statements of income. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in other comprehensive income is immediately reclassified into net income.

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price and locational risks on the forecasted sale of crude oil and natural gas that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. If significant transfers occur, they would be disclosed in Note 14 to the consolidated financial statements.

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities.

Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells in progress and those that find proved reserves, and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities, as well as property, plant and equipment unrelated to oil and gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets as summarized below.

Type of Asset	Range of Useful Lives
Office furniture, equipment and computer hardware	4 to 15 years
Pipelines	10 to 40 years
Plants, facilities and infrastructure	3 to 40 years

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income.

Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reflected in net gain (loss) on disposal of assets in our consolidated statements of income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized either when the assets are classified as held for sale, or are measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model depending on timing of the sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to a reporting unit. The fair value of a reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs – We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable. Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production facilities and equipment, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis based on estimated proved developed reserves for oil and gas production facilities, while accretion of the liability occurs over the useful lives of the assets.

Deferred income taxes – Deferred tax assets and liabilities, measured at enacted tax rates, are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include whether we are in a cumulative loss position in recent years, our reversal of temporary differences, and our expectation to generate sufficient future taxable income. We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected volatility of our stock price and the stock price in relation to the strike price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employees' behalf are presented within the financing activities section instead of the operating activities section of the statement of cash flows. We elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for the years ended December 31, 2016 or 2015. Excess tax benefits were classified as an operating activity within the statement of cash flows on a prospective basis beginning in 2017; as such, prior periods were not adjusted. See Note 2 for additional discussion.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

2. Accounting Standards

Not Yet Adopted

In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method. The adoption of this ASU will not have a material impact on our consolidated results of operations, financial position or cash flows. However, as a result of this standard we will change our presentation of marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the years ended December 31, 2017 and 2016, we expect the impact of this change to be a reduction of approximately $130 million and $100 million, respectively, in marketing revenue and expenses in our consolidated results of operations. We will provide the disclosures required by this standard, such as key sources of revenues from transactions with customers, disaggregated revenue information, and significant accounting estimates and judgments, beginning in the first quarter of 2018.

In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. We will adopt this standard in the first quarter of 2018 on a retrospective basis, and will reclassify certain amounts from general and administrative expense to the exploration, production and our new other net periodic benefit costs expense categories on our consolidated statements of income.

In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. We will adopt this standard during the first quarter of 2018 on a retrospective basis with no significant impact on our consolidated results of operations, financial position or cash flows.

In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. We will adopt this standard in the first quarter of 2018 on a retrospective basis and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. We will adopt this standard in the first quarter of 2018 using the modified retrospective approach with no material impact on our consolidated results of operations, financial position or cash flows.

In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. We will adopt this standard in the first quarter of 2018 on a prospective basis. Since we adopted the standard on a prospective basis, adoption of this standard will not have a significant impact on our consolidated results of operations, financial position or cash flows for prior periods.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. We plan to adopt this standard in the first quarter of 2018

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our consolidated results of operations, financial position or cash flows.

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this accounting standards update, including transition requirements, and are assessing the impact it may have on our results of operations, financial position, or cash flows.

In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

Recently Adopted

In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard was effective for us in the first quarter of 2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our financial statements.

In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in the first quarter of 2017, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

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Notes to Consolidated Financial Statements

3.    Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below exclude 11 million, 13 million and 13 million stock options in 2017, 2016 and 2015 that were antidilutive.

	Year Ended December 31,
(In millions, except per share data)	2017			2016			2015
Income (loss) from continuing operations	$	(830	)	$	(2,087	)	$	(1,701	)
Income (loss) from discontinued operations	(4,893		)	(53		)	(503		)
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Weighted average common shares outstanding	850			819			677
Per basic share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)
Per diluted share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)

4. Acquisitions

2017 - United States E&P

In the fourth quarter of 2017, we closed on our acquisition of additional acreage in the Northern Delaware basin of New Mexico from a private seller for $63 million in cash, subject to post-closing adjustments. We accounted for this transaction as an asset acquisition, allocating the purchase price to unproved property within property, plant and equipment.

In the second quarter of 2017, we closed on our acquisitions of approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin of New Mexico. On May 1, 2017, we closed on our acquisition with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately 70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017, we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment.

2016 - United States E&P

On August 1, 2016, we closed on our acquisition of PayRock Energy Holdings, LLC (“PayRock”), a portfolio company of EnCap Investments, including approximately 61,000 net surface acres in the oil window of the Anadarko Basin STACK play in Oklahoma. The purchase price of $904 million, subject to closing adjustments, was paid with cash on hand. We accounted for this transaction as an asset acquisition, with a majority of the purchase price allocated to unproved property within property, plant and equipment.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

5. Dispositions

Oil Sands Mining Segment

On May 31, 2017 we closed on the sale of our Canadian business, which included our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million. We recorded these notes receivable at fair value, see Note 14 for fair value measurements. Our notes receivable are with 10084751 Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant and equipment of our Canadian business. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business that were recorded in our financial statements but transferred to the buyer upon closing.

Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our consolidated statements of income as discontinued operations:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total sales and other revenues and other income	$	431		$	863		$	908
Net gain (loss) on disposal of assets	(43		)	—			—
Total revenues and other income	388			863			908
Costs and expenses:
Production expenses	254			601			715
Exploration expenses	—			7			347
Depreciation, depletion and amortization	40			239			236
Impairments	6,636			—			31
Other	25			87			98
Total costs and expenses	6,955			934			1,427
Pretax income (loss) from discontinued operations	(6,567		)	(71		)	(519		)
Provision (benefit) for income taxes	(1,674		)	(18		)	(16		)
Income (loss) from discontinued operations	$	(4,893	)	$	(53	)	$	(503	)

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and other non-core international assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at December 31, 2017 and December 31, 2016:

	December 31,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	—	$	2
Accounts receivables	—		129
Inventories	—		91
Other	—		4
Total current assets held for sale—discontinued operations	—		226
Total current assets held for sale—continuing operations	11		1
Total current assets held for sale	$	11	$	227
Noncurrent assets:
Property, plant and equipment, net	$	—	$	8,991
Other	—		106
Total noncurrent assets held for sale—discontinued operations	—		9,097
Total noncurrent assets held for sale—continuing operations	55		1
Total noncurrent assets held for sale	$	55	$	9,098
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	111
Other	—		10
Total current liabilities held for sale—discontinued operations	—		121
Total current liabilities held for sale—continuing operations	—		—
Total current liabilities held for sale	$	—	$	121
Noncurrent liabilities:
Asset retirement obligations	$	—	$	95
Deferred tax liabilities	—		1,669
Other	—		20
Total noncurrent liabilities held for sale—discontinued operations	—		1,784
Total noncurrent liabilities held for sale—continuing operations	2		7
Total noncurrent liabilities held for sale	$	2	$	1,791

United States E&P Segment

As disclosed above, we closed on the sale of our Canadian business in May of 2017. This sale included interests in our exploration stage in-situ leases which were included within our historically named North America E&P Segment. See Note 6 for further detail on our segments. These interests have been reflected as discontinued operations and are included within the disclosure above.

In July 2017, we entered into an agreement to sell certain conventional assets in Oklahoma. We closed on the sale in September 2017 for proceeds of $25 million, and recognized a pre-tax gain of $21 million.

In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas and New Mexico. The sale closed in late October for proceeds of $235 million, and we recognized a total pre-tax gain of $63

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Notes to Consolidated Financial Statements

million. During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to multiple purchasers for combined proceeds of approximately $67 million, and recognized a total pre-tax gain of $55 million.

In April 2016, we announced the sale of our Wyoming upstream and midstream assets. During the second quarter, we received proceeds of approximately $690 million and recorded a pre-tax gain of $266 million with the remaining asset sales closing in November 2016 for proceeds of $155 million, excluding closing adjustments. A pre-tax gain of $38 million was recognized in the fourth quarter 2016.

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds. We closed on certain of the asset sales and recognized a net pre-tax loss on sale of $48 million in 2016, the remaining asset closed in 2017 with a net pre-tax gain on sale of $32 million.

In November 2015, we entered into an agreement to sell our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius and Neptune fields in the Gulf of Mexico. The transaction closed in December 2015, excluding the Neptune field, for proceeds of $111 million. A $228 million pretax gain was recorded in the fourth quarter of 2015. The Neptune field transaction closed during the first quarter of 2016 for cash proceeds of $4 million.

In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (see Note 14).

International E&P Segment

In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the second half of 2017 and recognized no net pre-tax gain or loss on sale. The remaining asset sale is expected to close during 2018 and is classified as held for sale in the consolidated balance sheet as of December 31, 2017, with total assets of $66 million and total liabilities of $2 million. See Note 10 for further detail on impairment expenses recognized concurrently with these agreements.

In the third quarter of 2015, we entered into agreements to sell our East Africa exploration acreage in Ethiopia and Kenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction closed during the first quarter of 2016.

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Notes to Consolidated Financial Statements

6. Segment Information

We have two reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• United States E&P ("U.S. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

• International E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income (loss) represents income (loss) which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, changes in our valuation allowance, unrealized gains or losses on derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

As discussed in Note 5, we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases, in the second quarter of 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented. Additionally, we renamed our North America E&P segment to United States E&P segment effective June 30, 2017 in all periods presented. See Note 1 for further information.

Year Ended December 31, 2017						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,138		$	1,154	$	(81	)	(b)	$	4,211
Marketing revenues	29			133		—				162
Total revenues	3,167			1,287		(81		)		4,373
Income from equity method investments	—			256		—				256
Net gain on disposal of assets and other income	13			6		117			(c)	136
Less:
Production expenses	476			229		1				706
Marketing costs	36			132		—				168
Other operating	354			77		—				431
Exploration	154			5		250			(d)	409
Depreciation, depletion and amortization	2,011			328		33				2,372
Impairments	4			—		225			(e)	229
Taxes other than income	173			—		10				183
General and administrative	119			32		249			(f)	400
Net interest and other	—			—		270			(g)	270
Loss on early extinguishment of debt	—			—		51			(h)	51
Income tax provision (benefit)	1			372		3				376
Segment income (loss) / Income (loss) from continuing operations	$	(148	)	$	374	$	(1,056	)		$	(830	)
Capital expenditures (a)	$	2,081		$	42	$	27			$	2,150

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to sale of certain conventional assets in Oklahoma and Colorado. (See Note 5).

^(d) Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(e)  Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(f)   Includes pension settlement loss of $32 million (see Note 17).

^(g) Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 13.)

^(h) Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 15.)

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Notes to Consolidated Financial Statements

Year Ended December 31, 2016						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	2,375		$	665	$	(110	)	(b)	$	2,930
Marketing revenues	135			105		—				240
Total revenues	2,510			770		(110		)		3,170
Income (loss) from equity method investments	—			175		—				175
Net gain on disposal of assets and other income	28			32		382			(c)	442
Less:
Production expenses	486			226		—				712
Marketing costs	142			103		—				245
Other operating	328			43		113			(d)	484
Exploration	127			17		179			(e)	323
Depreciation, depletion and amortization	1,835			276		45				2,156
Impairments	20			—		47			(f)	67
Taxes other than income	149			—		2				151
General and administrative	94			35		352			(g)	481
Net interest and other	—			—		332				332
Income tax provision (benefit)	(228		)	49		1,102			(h)	923
Segment income (loss) / Income (loss) from continuing operations	$	(415	)	$	228	$	(1,900	)		$	(2,087	)
Capital expenditures (a)	$	936		$	82	$	18			$	1,036

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to net gain on disposal of assets(see Note 5).

^(d)  Includes termination payment on our Gulf of Mexico deepwater drilling rig commitment of $113 million.

^(e) Primarily related to impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (See Note 10).

^(f)  Proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $103 million and severance related expenses associated with workforce reductions of $8 million (see Note 17).

^(h)  Increased valuation allowance on certain of our deferred tax assets $1,346 million (see Note 7).

Year Ended December 31, 2015						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,358		$	728	$	50		(b)	$	4,136
Marketing revenues	396			103		—				499
Total revenues	3,754			831		50				4,635
Income from equity method investments	—			157		(12		)	(c)	145
Net gain on disposal of assets and other income	24			27		122			(d)	173
Less:
Production expenses	724			255		—				979
Marketing costs	401			99		—				500
Other operating	335			48		27				410
Exploration	314			101		556			(e)	971
Depreciation, depletion and amortization	2,377			295		49				2,721
Impairments	2			—		719			(f)	721
Taxes other than income	215			—		1				216
General and administrative	127			44		417			(g)	588
Net interest and other	—			—		286				286
Income tax provision (benefit)	(265		)	61		(534		)		(738		)
Segment income (loss) / Income (loss) from continuing operations	$	(452	)	$	112	$	(1,361	)		$	(1,701	)
Capital expenditures (a)	$	2,553		$	368	$	25			$	2,946

^(a)  Includes accruals.

^(b)  Unrealized gain on commodity derivative instruments.

^(c)  Partial impairment of investment in equity method investee (See Note 14).

^(d)  Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage(see Note 5).

^(e) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 10).

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Notes to Consolidated Financial Statements

^(f)  Includes goodwill impairment (see Note 12) and proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $119 million (see Note 17) and severance related expenses associated with workforce reductions of $55 million.

Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.

	Year Ended December 31,
(In millions)	2017		2016		2015
United States	$	3,086	$	2,400	$	3,804
Equatorial Guinea	530		444		444
Libya	431		54		—
U.K.	289		263		380
Other international	37		9		7
Total revenues	$	4,373	$	3,170	$	4,635

In 2017, sales to Vitol and each of their respective affiliates accounted for approximately 10% of our total revenues. In 2016, sales to Valero Marketing and Supply, Tesoro Petroleum, and Flint Hills Resources and each of their respective affiliates accounted for approximately 13%, 11% and 10% of our total revenues. In 2015, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues.

The following summarizes revenues by product line.

	Year Ended December 31,
(In millions)	2017		2016		2015
Crude oil and condensate	$	3,477	$	2,605	$	3,963
Natural gas liquids	338		198		203
Natural gas	510		356		464
Other	48		11		5
Total revenues	$	4,373	$	3,170	$	4,635

The following summarizes property, plant and equipment and equity method investments.

	December 31,
(In millions)	2017		2016
United States	$	15,971	$	14,272
Equatorial Guinea	1,582		1,794
Other international	959		1,592
Total long-lived assets	$	18,512	$	17,658

7. Income Taxes

Income (loss) before tax expense for continuing operations was:

	Year Ended December 31,
(In millions)		2017			2016			2015
United States		$	(783	)	$	(1,449	)	$	(2,384	)
Foreign		329			285			(55		)
Total		$	(454	)	$	(1,164	)	$	(2,439	)

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Notes to Consolidated Financial Statements

Income tax provisions (benefits) for continuing operations were:

	Year Ended December 31,
	2017									2016							2015
(In millions)	Current			Deferred			Total			Current		Deferred			Total		Current			Deferred			Total
Federal	$	(32	)	$	41		$	9		$	2	$	836		$	838	$	(41	)	$	(684	)	$	(725	)
State and local	(14		)	2			(12		)	2		8			10		(8		)	(18		)	(26		)
Foreign	483			(104		)	379			91		(16		)	75		115			(102		)	13
Total	$	437		$	(61	)	$	376		$	95	$	828		$	923	$	66		$	(804	)	$	(738	)

A reconciliation of the federal statutory income tax rate applied to income (loss) from continuing operations before income taxes to the provision (benefit) for income taxes follows:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total pre-tax income (loss) from continuing operations	$	(454	)	$	(1,164	)	$	(2,439	)
Total income tax expense (benefit)	$	376		$	923		$	(738	)
Effective income tax expense (benefit) rate on continuing operations	83		%	79		%	(30		)%
Income taxes at the statutory tax rate of 35% (a)	$	(159	)	$	(407	)	$	(854	)
Effects of foreign operations	140			47			(55		)
Adjustments to valuation allowances	446			1,270			95
State income taxes	(19		)	9			(15		)
Tax law change	(35		)	6			(3		)
Goodwill impairment	—			—			94
Other federal tax effects	3			(2		)	—
Income tax expense (benefit) on continuing operations	$	376		$	923		$	(738	)

^(a) Includes income tax benefits primarily related to our U.S. federal income taxes where we have maintained a full valuation allowance since December 2016.

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments appears in the "Not Allocated to Segments" column of the tables in Note 6.

Effects of foreign operations – The effects of foreign operations increased our tax expense in 2017, 2016, and 2015 due to the mix of pretax income between high and low tax jurisdictions. This increase primarily relates to increased sales volumes in Libya during 2017 where the tax rate is 93.5%. Excluding Libya, the effective tax rates on continuing operations would be an expense of 5% in 2017, an expense of 79% in 2016, and a benefit of 29% in 2015.

Adjustments to valuation allowances - Since December 31, 2016, we have maintained a full valuation allowance on our net federal deferred tax assets. In 2017, we recorded a $446 million valuation allowance primarily related to current year activity in the U.S. Included within the $446 million is a $41 million out-of-period adjustment as a result of identifying certain deferred tax assets for which the impact should have been recorded to other comprehensive income, but had been recorded to income from continuing operations in 2016.

Change in tax law – On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”). Tax Reform Legislation, which is also commonly referred to as “U.S. tax reform”, significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018, and repeal of the corporate alternative minimum tax (“AMT”), and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. The impact of the remeasurement on our federal deferred tax assets and liabilities was equally offset by an adjustment to our valuation allowance with no material impact to current year earnings. We recorded a net benefit of $35 million, classified as a receivable within other noncurrent assets on the consolidated balance sheet, during the fourth quarter of 2017 related to the repeal of the corporate AMT. Although the $35 million net benefit represents what we believe is a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We do

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Notes to Consolidated Financial Statements

not expect to pay U.S. federal cash taxes on the deemed repatriation due to an accumulated deficit in foreign earnings for tax purposes.

Once we finalize certain tax positions when we file our 2017 federal tax return, we will be able to conclude whether any further adjustments are required to our net tax position as of December 31, 2017. Any adjustments to these provisional amounts will be reported as a component of income tax expense (benefit) in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018.

Deferred tax assets and liabilities resulted from the following:

	Year Ended December 31,
(In millions)	2017			2016
Deferred tax assets:
Employee benefits	$	111		$	228
Operating loss carryforwards	1,030			1,065
Capital loss carryforwards	3			4
Foreign tax credits	611			4,430
Other credit carryforwards	—			35
Investments in subsidiaries and affiliates	174			91
Other	69			86
Subtotal	1,998			5,939
Valuation Allowance	(926		)	(4,301		)
Total deferred tax assets	1,072			1,638
Deferred tax liabilities:
Property, plant and equipment	1,332			3,672
Accrued revenue	81			75
Other	3			(7		)
Total deferred tax liabilities	1,416			3,740
Net deferred tax liabilities	$	344		$	2,102

Foreign Tax Credits - As a result of U.S. tax reform, we have reduced our foreign tax credits at December 31, 2017, which are offset by a corresponding reduction in valuation allowance, by $3,819 million due to the remote likelihood these credits will be utilized before expiration. We have not elected any of our foreign earnings to be permanently reinvested abroad. Additionally due to U.S. tax reform, we do not expect future foreign earnings from operations to be subject to tax in the U.S. The remaining foreign tax credits, which are offset by a valuation allowance, expire in 2022 through 2027.

Operating loss carryforwards - At December 31, 2017, our operating loss carryforwards before valuation allowance includes $898 million from the U.S. that expire in 2035-2037. Foreign operating loss carryforwards include $13 million that begin to expire in 2018. State operating loss carryforwards of $119 million expire in 2018 through 2037.

Valuation allowances – At December 31, 2017, we reflect a valuation allowance in our consolidated balance sheet of $926 million against our net deferred tax assets in various jurisdictions in which we operate. The reduction primarily related to the reduction of foreign tax credits in the U.S. In 2016 and 2015, we increased our valuation allowance by $1,268 million and $99 million respectively.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2017		2016
Assets:
Other noncurrent assets	$	489	$	336
Liabilities:
Noncurrent deferred tax liabilities	833		769
Noncurrent liabilities held for sale	—		1,669
Net deferred tax liabilities	$	344	$	2,102

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been completed through the 2014 tax year, with the exception of 2010-11. During the third quarter of 2017, we received a

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Notes to Consolidated Financial Statements

partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the fourth quarter of 2017. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. See Note 24 for further detail. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.

As of December 31, 2017, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2008-2016
Equatorial Guinea	2007-2016
Libya	2012-2016
United Kingdom	2008-2016

^(a)  Includes federal and state jurisdictions.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2017			2016			2015
Beginning balance	$	66		$	65		$	80
Additions for tax positions of prior years	83			6			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Settlements	(20		)	—			(7		)
Statute of limitations	—			—			(9		)
Ending balance	$	126		$	66		$	65

If the unrecognized tax benefits as of December 31, 2017 were recognized, $10 million would affect our effective income tax rate. As of December 31, 2017, there are $83 million uncertain tax positions for which it is reasonably possible that the amount could significantly change during the next twelve months. If this were to significantly change, we estimate that any revisions to current and deferred tax liabilities would have no cumulative adverse earnings impact on our consolidated results of operations.

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs. In the fourth quarter of 2017, we received an adverse ruling from the U.K. first-tier tax tribunal. As a result of the adverse ruling, in the fourth quarter of 2017 we established an uncertain tax position. We have appealed the ruling, but were required to pay the disputed tax amount and associated interest in order to pursue the appeal. The payment of the disputed tax and interest, approximately $108 million, is not considered a settlement of the tax dispute with the U.K. tax authorities. If we prevail in appeals, we will be refunded the tax and interest paid, however, if we do not prevail no further material cash payments are expected due to the initial payment required to appeal the adverse ruling. See Note 24 for further detail.

Interest and penalties are recorded as part of the tax provision and were $2 million, $1 million and $1 million related to unrecognized tax benefits in 2017, 2016 and 2015. As of December 31, 2017 and 2016, $25 million and $15 million of interest and penalties were accrued related to income taxes.

8. Inventories

Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

	December 31,
(In millions)	2017		2016
Crude oil and natural gas	$	9	$	6
Supplies and other items	117		130
Inventories	$	126	$	136

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Notes to Consolidated Financial Statements

9. Property, Plant and Equipment

	December 31,
(In millions)	2017		2016
United States E&P	$	15,867	$	14,158
International E&P	1,710		2,470
Corporate	88		99
Net property, plant and equipment	$	17,665	$	16,727

At December 31, 2017, 2016 and 2015 we had total deferred exploratory well costs as follows:

	December 31,
(In millions)	2017			2016			2015
Amounts capitalized less than one year after completion of drilling	$	263		$	131		$	352
Amounts capitalized greater than one year after completion of drilling	32			118			85
Total deferred exploratory well costs	$	295		$	249		$	437
Number of projects with costs capitalized greater than one year after
completion of drilling	1			3			2
(In millions)	2017			2016			2015
Beginning balance	$	249		$	437		$	573
Additions	212			299			610
Charges to expense (a)	(64		)	(23		)	(111		)
Transfers to development	(102		)	(388		)	(635		)
Dispositions(b)	—			(76		)	—
Ending balance	$	295		$	249		$	437

^(a)  Includes $64 million in exploratory well costs being expensed as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon in August of 2017. See Note 10 for further detail.

^(b)  Includes sale of GOM assets in 2016.

Exploratory well costs capitalized greater than one year after completion of drilling are associated with one project in E.G. with costs of $32 million as of December 31, 2017. Management believes this project with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development based on current plans. For this project in E.G., drilling was completed on the Rodo well in Alba Block Sub Area B, offshore E. G. in the first quarter of 2015, and we have since completed a seismic feasibility study. In 2017, we received approval for and proceeded to perform a seismic reprocessing program. After completion of this program we will evaluate drilling opportunities within Sub Area B.

10. Impairments and Exploration Expenses

Impairments

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment in our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented

The following table summarizes impairment charges of proved properties:

	Year Ended December 31,
(in millions)	2017		2016		2015
Total impairments	$	229	$	67	$	721

• 2017 - Impairments were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment of $136 million. Additionally, included in proved property impairments was $89 million relating to the Gulf of Mexico and certain conventional Oklahoma assets primarily as a result of lower forecasted long-term commodity prices.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

• 2016 - Impairments of $67 million consisted primarily of proved properties in Oklahoma and the Gulf of Mexico as a result of lower forecasted commodity prices and revisions to estimated abandonment costs.

• 2015 - Impairments included $340 million for the goodwill impairment of the United States E&P reporting unit, and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma.

See Note 6 for relevant detail regarding segment presentation, Note 12 for further detail regarding the goodwill impairment and Note 14 for fair value measurements related to impairments of proved properties and long-lived assets.

Exploration expense

The following table summarizes the components of exploration expenses:

	Year Ended December 31,
(In millions)	2017		2016		2015
Exploration Expenses
Unproved property impairments	$	246	$	195	$	655
Dry well costs	77		25		212
Geological and geophysical	25		5		31
Other	61		98		73
Total exploration expenses	$	409	$	323	$	971

Unproved property impairments and dry well costs

• 2017 - As a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our International E&P segment, we recorded a non-cash charge of $159 million comprised of $95 million in unproved property impairments; and $64 million in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of Gabon, we recorded a non-cash impairment charge of $43 million to unproved property.

• 2016 - Unproved property impairments recorded of $195 million were primarily a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in the United States. Lower dry well expense was a result of the strategic decision to transition out of our conventional exploration program during 2015.

• 2015 - Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved property impairment mentioned above. Dry well costs include the operated Solomon exploration well in the Gulf of Mexico, and our operated Sodalita West #1 exploratory well in E.G.

See Note 6 for relevant detail regarding segment presentation of unproved property impairments.

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Notes to Consolidated Financial Statements

11. Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations were as follows:

	For Year Ended December 31,
(In millions)	2017			2016
Beginning balance	$	1,652		$	1,544
Incurred liabilities, including acquisitions	25			14
Settled liabilities, including dispositions	(50		)	(74		)
Accretion expense (included in depreciation, depletion and amortization)	85			79
Revisions of estimates	(227		)	96
Held for sale	(2		)	(7		)
Ending balance	$	1,483		$	1,652

2017

• Settled liabilities include dispositions, primarily related to the sale of certain conventional assets in Oklahoma as well as retirements in the U.K. and the Gulf of Mexico.

• Revisions of estimates were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.

• Ending balance includes $55 million classified as short-term at December 31, 2017.

2016

• Settled liabilities include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.

• Revisions of estimates were primarily due to changes in timing of abandonment activities as well as changes in cost estimated in the U.K.

• Ending balance includes $50 million classified as short-term at December 31, 2016.

12. Goodwill

Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. We performed our annual impairment test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40%. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in such assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

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Notes to Consolidated Financial Statements

The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2017 and 2016:

(In millions)	U.S. E&P		Int'l E&P		Total
2016
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115
2017
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115

13. Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 14. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our commodity derivatives and historical interest rate derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	December 31, 2017
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Not Designated as Hedges
Commodity	$	—	$	138	$	(138	)	Other current liabilities
Commodity	—		2		(2		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	140	$	(140	)
Total	$	—	$	140	$	(140	)

	December 31, 2016
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate	$	3	$	—	$	3		Other current assets
Interest rate	1		—		1			Other noncurrent assets
Cash Flow Hedges
Interest rate	$	64	$	—	$	64		Other noncurrent assets
Total Designated Hedges	$	68	$	—	$	68
Not Designated as Hedges
Commodity	$	—	$	60	$	(60	)	Other current liabilities
Total Not Designated as Hedges	$	—	$	60	$	(60	)
Total	$	68	$	60	$	8

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Notes to Consolidated Financial Statements

Derivatives Designated as Fair Value Hedges

During the third quarter of 2017, we terminated all of our interest rate swaps designated as fair value hedges. The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income has a gross impact that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value hedges in all periods presented.

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”) based, floating rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	—	—	%	$	600	5.10	%
March 15, 2018	$	—	—	%	$	300	5.04	%

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income is summarized in the table below. There is no ineffectiveness related to the historical fair value hedges.

		Gain (Loss)
		Year Ended December 31,
(In millions)	Income Statement Location	2017		2016			2015
Derivative
Interest rate	Net interest and other	$	—	$	(4	)	$	—
Hedged Item
Debt	Net interest and other	$	—	$	4		$	—

Derivatives Not Designated as Hedges

Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow hedges. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. See Note 15 for further detail. As a result, we terminated our forward starting interest rate swaps receiving proceeds of $54 million. We recognized a gain of $47 million, related to deferred gains reclassified from accumulated other comprehensive income, in net interest and other during 2017.

The following table presents, by maturity date, information about our terminated forward starting interest rate swap agreements, including the rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR		Aggregate Notional Amount		Weighted Average, LIBOR
Maturity Dates	(in millions)		Fixed Rate		(in millions)		Fixed Rate
March 15, 2018	$	—	—	%	$	750	1.57	%

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Notes to Consolidated Financial Statements

The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest Rate Swaps
Beginning balance	$	60		$	—		$	—
Change in fair value recognized in other comprehensive income	(13		)	64			—
Reclassification from other comprehensive income	(47		)	(4		)	—
Ending balance	$	—		$	60		$	—

Commodity Derivatives

We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States E&P sales through 2019. These commodity derivatives consist of three-way collars, swaps, and basis swaps. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of December 31, 2017 and the weighted average prices for those contracts:

Crude Oil
	2018				2019
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars (a)
Volume (Bbls/day)	85,000	85,000	85,000	85,000	10,000	10,000
Weighted average price per Bbl:
Ceiling	$56.38	$56.38	$56.96	$56.96	$60.00	$60.00
Floor	$51.65	$51.65	$51.53	$51.53	$55.00	$55.00
Sold put	$45.00	$45.00	$44.65	$44.65	$47.00	$47.00
Swaps
Volume (Bbls/day)	20,000	20,000	—	—	—	—
Weighted average price per Bbl	$55.12	$55.12	$—	$—	$—	$—
Basis Swaps (b)
Volume (Bbls/day)	5,000	5,000	10,000	10,000	—	—
Weighted average price per Bbl	$(0.60)	$(0.60)	$(0.67)	$(0.67)	$—	$—

^(a)  Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.

^(b)  The basis differential price is between WTI Midland and WTI Cushing.

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Notes to Consolidated Financial Statements

Natural Gas
	2018
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	200,000	160,000	160,000	160,000
Weighted average price per MMBtu
Ceiling	$3.79	$3.61	$3.61	$3.61
Floor	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.50	$2.50	$2.50

The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the years ended December 31, 2017, 2016, and 2015. The December 31, 2017, 2016, and 2015 impact was a net loss of $36 million, a net loss of $66 million, and a net gain of $128 million, respectively. Net settlements of commodity derivative instruments for the years ended December 31, 2017, 2016, and 2015 were gains of $45 million, $44 million, and $78 million, respectively.

14. Fair Value Measurements

Fair values – Recurring

The following tables' present assets and liabilities accounted for at fair value on a recurring basis by hierarchy level.

	December 31, 2017
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	—			—			—		—
Derivative instruments, assets	$	—		$	—		$	—	$	—
Derivative instruments, liabilities
Commodity (a)	$	(20	)	$	(120	)	$	—	$	(140	)
Derivative instruments, liabilities	$	(20	)	$	(120	)	$	—	$	(140	)
	December 31, 2016
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	$	—		$	68		$	—	$	68
Derivative instruments, assets	$	—		$	68		$	—	$	68
Derivative instruments, liabilities
Commodity (a)	$	—		$	60		$	—	$	60
Derivative instruments, liabilities	$	—		$	60		$	—	$	60

^(a) Derivative instruments are recorded on a net basis in our balance sheet (see Note 13).

Commodity derivatives include three-way collars, swaps, and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include commodity prices and interest rates and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars, inputs to the models include commodity prices, interest rates, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Historically, both our interest rate swaps and forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 13 for additional discussion of the types of derivative instruments we use.  

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Notes to Consolidated Financial Statements

Fair values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2017				2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	179	$	229	$	15	$	67	$	56	$	386

Long-lived assets held for use that were impaired are discussed below. The fair values, unless otherwise noted, were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.

United States E&P

In the third quarter of 2017, impairments of $65 million were recorded consisting of certain proved properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $66 million.

In the third quarter of 2016, impairments of $47 million were recorded consisting primarily of conventional non-core proved properties in Oklahoma as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $15 million. During the fourth quarter of 2016, we recorded an impairment of $17 million as a result of abandonment cost revisions related to the Ozona development in the Gulf of Mexico which ceased productions in 2013.

In the third quarter of 2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.

During the second quarter of 2015, we recorded an impairment charge of $44 million related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale. The fair values were measured using a probability weighted income approach based on both the anticipated sale price and held-for-use model.

International E&P

In the third quarter of 2017, we recorded proved property impairments of $136 million, to an aggregate fair value of $103 million, on certain non-core properties in our International E&P segment primarily as a result of lower forecasted long-term commodity prices and as a result of the anticipated sales of certain non-core international assets. The fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe. This resulted in a Level 2 classification. See Note5 for further information about the divestment of certain non-core properties in our International E&P segment.

In the third quarter of 2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, to a fair value of $604 million. The impairment was reflected in income from equity method investments in our consolidated statement of income.

Canadian discontinued operations

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 5 for relevant detail regarding dispositions

Fair values – Financial instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

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Notes to Consolidated Financial Statements

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2017 and 2016.

	December 31,
	2017				2016
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other current assets (a)	$	762	$	761	$	7	$	7
Other noncurrent assets	159		161		105		108
Total financial assets	$	921	$	922	$	112	$	115
Financial liabilities
Other current liabilities	$	32	$	43	$	68	$	75
Long-term debt, including current portion (b)	5,976		5,526		7,449		7,292
Deferred credits and other liabilities	110		103		114		107
Total financial liabilities	$	6,118	$	5,672	$	7,631	$	7,474

^(a)  Includes our two notes receivable relating to the sale of our Canadian business as of December 31, 2017, see note 5 for further information.

^(b)  Excludes capital leases, debt issuance costs and historical interest rate swap adjustments.

Fair values of our notes receivable and our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

15. Debt

Short-term debt

As of December 31, 2017, we had no borrowings against our $3.4 billion unsecured revolving credit facility (as amended, the "Credit Facility"), as described below.

Revolving Credit Facility

In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. 

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of December 31, 2017, we were in compliance with this covenant with a debt-to-capitalization ratio of 32%.

Long-term debt

The following table details our long-term debt:

	December 31,
(In millions)	2017			2016
Senior unsecured notes:
6.000% notes due 2017	—			682
5.900% notes due 2018	—			854
7.500% notes due 2019	—			228
2.700% notes due 2020(a)	600			600
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022 (b)	32			32
Series A notes due 2022 (b)	3			3
8.500% notes due 2023 (b)	70			70
8.125% notes due 2023 (b)	131			131
3.850% notes due 2025(a)	900			900
4.400% notes due 2027(a)	1,000			—
6.800% notes due 2032(a)	550			550
6.600% notes due 2037(a)	750			750
5.200% notes due 2045(a)	500			500
Capital leases:
Capital lease obligation expiring in 2018	—			1
Other obligations:
5.125% obligation relating to revenue bonds due 2037	—			1,000
Total(b)	5,536			7,301
Unamortized discount	(10		)	(9		)
Fair value adjustments(c)	—			7
Unamortized debt issuance cost	(32		)	(35		)
Amounts due within one year	—			(683		)
Total long-term debt	$	5,494		$	6,581

^(a)  These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2017 may be declared immediately due and payable.

^(c)  See Notes 13 and 14 for information on historical interest rate swaps.

86

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Debt Issuance

On July 24, 2017, we issued $1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the senior unsecured notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior unsecured notes at any time at the applicable redemption price, plus accrued interest, if any. During the third quarter of 2017, we used the net proceeds of $990 million plus existing cash on hand to redeem the following senior unsecured notes:

• $682 million6.0% Notes Due in 2017

• $854 million5.9% Notes Due in 2018

• $228 million7.5% Notes Due in 2019

During the year ended 2017, as a result of the above redemption of $1.76 billion in senior unsecured notes, we recognized a loss on early extinguishment of debt of $46 million, primarily due to make-whole call provisions. In connection with the redemption of the senior unsecured notes, we terminated our forward starting interest rate swaps, which resulted in proceeds of $54 million and a gain of approximately $47 million into earnings in 2017. See Note 13 for further detail on our historical forward starting interest rate swaps.

Debt Redemption

In December 2017, we entered into a transaction to purchase $1 billion of 3.75% municipal revenue bonds due in 2037, to be issued by the Parish of St. John the Baptist, State of Louisiana (the "Parish"). The Parish will use the proceeds to redeem $1 billion of 5.125% municipal revenue bonds due in 2037 with cash on hand in a refunding transaction. We purchased the $1 billion of 3.75% municipal revenue bonds due in 2037 on their date of issuance to hold for our own account and potential remarketing to the public at a future date.

The following table shows future debt payments:

(In millions)
2018	$	—
2019	—
2020	600
2021	—
2022	1,035
Thereafter	3,901
Total long-term debt, including current portion	$	5,536

16. Incentive Based Compensation

Description of stock-based compensation plans – The Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan") was approved by our stockholders in May 2016 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance unit awards to employees. The 2016 Plan also allows us to provide equity compensation to our non-employee directors. No more than 55 million shares of our common stock may be issued under the 2016 Plan. For stock options and SARs, the number of shares available for issuance under the 2016 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted. For stock awards (including restricted stock and restricted stock unit awards), the number of shares available for issuance under the 2016 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.

Shares subject to awards under the 2016 Plan that are forfeited, terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2016 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2016 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

After approval of the 2016 Plan, no new grants were or will be made from any prior plans. Any awards previously granted under any prior plans shall continue to be exercisable in accordance with their original terms and conditions.

Stock-based awards under the plans

Stock options – We grant stock options under the 2016 Plan. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

SARs - At December 31, 2017, there are no SARs outstanding.

Restricted stock – We grant restricted stock under the 2016 Plan. The restricted stock awards granted to officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest ratably over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares of restricted stock are not transferable and are held by our transfer agent.

Stock-based performance units – We grant stock-based performance units to officers under the 2016 Plan. At the grant date, each unit represents the value of one share of our common stock. These units are settled in cash, and the amount of the payment is based on (1) the vesting percentage, which can be from zero to 200% based on performance achieved and (2) the value of our common stock on the date vesting is determined by the Compensation Committee of the Board of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the performance period and would be paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.

Restricted stock units – We maintain an equity compensation program for our non-employee directors.  All non-employee directors receive annual grants of common stock units.  Any units granted prior to 2012 must be held until completion of board

87

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

service, at which time the non-employee director will receive common shares.  For units granted between 2012 and 2016, common shares will generally vest following completion of board service or three years from the date of grant, whichever is earlier.  For awards issued in 2017 and later, directors may elect to defer settlement of their common stock units until after they cease serving on the Board.  Absent such an election to defer, common shares will vest upon the earlier of three years from the date of grant or completion of board service.  We also grant restricted stock units to certain non-officer international employees which generally vest ratably over a three-year period, contingent on the recipient's continued employment. Grants of restricted stock units to these non-officer international employees are based on their performance and for retention purposes. Common shares will be issued for these restricted stock units after vesting. Prior to vesting, recipients of restricted stock units typically receive dividend equivalent payments, but they may not vote.

Total stock-based compensation expense – Total employee stock-based compensation expense was $50 million, $51 million and $57 million in 2017, 2016 and 2015, while the total related income tax benefits were $19 million and $20 million in 2016 and 2015. Due to the full valuation allowance on our net federal deferred tax assets, we realized no tax benefit during 2017. During 2016 and 2015, cash received upon exercise of stock option awards was $1 million and $9 million. There was no cash received upon exercise of stock option awards for 2017. There were no tax benefits realized for deductions for stock awards settled during 2017, 2016 and 2015.

Stock option awards – During 2017, 2016 and 2015 we granted stock option awards to officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2017		2016		2015
Exercise price per share	$15.80		$7.22		$29.06
Expected annual dividend yield	1.3	%	2.8	%	2.9	%
Expected life in years	6.4		6.3		6.2
Expected volatility	42	%	36	%	32	%
Risk-free interest rate	2.1	%	1.4	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$6.07		$1.97		$6.84

The following is a summary of stock option award activity in 2017.

	Number	Weighted Average	Weighted Average Remaining	Aggregate Intrinsic Value
	of Shares	Exercise Price	Contractual Term	(in millions)
Outstanding at beginning of year	11,915,533	$27.71
Granted	799,591	$15.80
Exercised	(8,666)	$7.22
Canceled	(2,375,682)	$33.31
Outstanding at end of year	10,330,776	$25.52	4 years	$	13
Exercisable at end of year	8,661,893	$27.91	3 years	$	5
Expected to vest	1,650,737	$13.08	9 years	$	8

The intrinsic value of stock option awards exercised during 2017 and 2016 were not material. The intrinsic value of stock awards exercised during 2015 was $6 million.

As of December 31, 2017, unrecognized compensation cost related to stock option awards was $4 million, which is expected to be recognized over a weighted average period of one year.

88

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Restricted stock awards and restricted stock units – The following is a summary of restricted stock and restricted stock unit award activity in 2017.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	6,933,533		$14.44
Granted	4,198,624		$16.13
Vested & Exercised	(2,472,367	)	$17.67
Canceled	(1,086,945	)	$15.03
Unvested at end of year	7,572,845		$14.24

The vesting date fair value of restricted stock awards which vested during 2017, 2016 and 2015 was $30 million, $16 million and $26 million. The weighted average grant date fair value of restricted stock awards was $14.24, $14.44 and $30.76 for awards unvested at December 31, 2017, 2016 and 2015.

As of December 31, 2017 there was $67 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of one year.

Stock-based performance unit awards – During 2017, 2016 and 2015 we granted 563,631, 1,205,517 and 382,335 stock-based performance unit awards to officers. At December 31, 2017, there were 1,510,823 units outstanding. Total stock-based performance unit awards expense was $8 million in 2017 and $6 million in 2016. We had no stock-based performance unit awards expense in 2015.

The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units granted in 2017, 2016 and 2015 were:

	2017		2016		2015 (a)
Valuation date stock price	$16.93		$16.93		$16.93
Expected annual dividend yield	1.2	%	1.2	%	1.2	%
Expected volatility	54	%	34	%	33	%
Risk-free interest rate	1.9	%	1.7	%	1.4	%
Fair value of stock-based performance units outstanding	$21.63		$19.86		$0.00

^(a) As of December 31, 2017, there were no 2015 performance unit awards outstanding.

17. Defined Benefit Postretirement Plans and Defined Contribution Plan

We have noncontributory defined benefit pension plans covering substantially all domestic employees, as well as U.K. employees who were hired before April 2010. Certain employees located in E.G., who are U.S. or U.K. based, also participate in these plans. Benefits under these plans are based on plan provisions specific to each plan. For the U.K. pension plan, the principal employer and plan trustees reached a decision to close the plan to future benefit accruals effective December 31, 2015.

We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided up to age 65 through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Post-age 65 health care benefits are provided to certain U.S. employees on a defined contribution basis. Life insurance benefits are provided to certain retiree beneficiaries. These other postretirement benefits are not funded in advance. Employees hired after 2016 are not eligible for any postretirement health care or life insurance benefits.

89

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Obligations and funded status– The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.    

	Pension Benefits												Other Benefits
	2017						2016						2017			2016
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			U.S.
Accumulated benefit obligation	378			599			386			583			221			227
Change in benefit obligations:
Beginning balance	$	397		$	583		$	525		$	579		$	227		$	260
Service cost	22			—			25			—			2			2
Interest cost	13			17			16			23			8			11
Plan amendment	—			—			—			1			—			(38		)
Actuarial loss (gain)	42			(7		)	78			139			5			11
Foreign currency exchange rate changes	—			52			—			(108		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(19		)
Ending balance	$	384		$	599		$	397		$	583		$	221		$	227
Change in fair value of plan assets:
Beginning balance	$	227		$	595		$	354		$	608		$	—		$	—
Actual return on plan assets	27			47			25			129			—			—
Employer contributions	52			17			95			18			21			20
Foreign currency exchange rate changes	—			57			—			(109		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(20		)
Ending balance	$	216		$	670		$	227		$	595		$	—		$	—
Funded status of plans at December 31	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	—			71			—			12			—			—
Current liabilities	(6		)	—			(4		)	—			(21		)	(21		)
Noncurrent liabilities	(162		)	—			(166		)	—			(200		)	(206		)
Accrued benefit cost	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	122		$	58		$	130		$	81		$	30		$	25
Prior service cost (credit)	(45		)	3			(55		)	4			(56		)	(63		)

90

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Components of net periodic benefit cost from continuing operations and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits																		Other Benefits
	Year Ended December 31,																		Year Ended December 31,
	2017						2016						2015						2017			2016			2015
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			U.S.			U.S.			U.S.
Components of net periodic benefit cost:
Service cost	$	22		$	—		$	25		$	—		$	29		$	14		$	2		$	2		$	3
Interest cost	13			17			16			23			25			25			8			11			11
Expected return on plan assets	(13		)	(30		)	(18		)	(35		)	(30		)	(37		)	—			—			—
Amortization:
- prior service cost (credit)	(10		)	—			(10		)	1			(7		)	1			(7		)	(3		)	(4		)
- actuarial loss	8			1			14			—			22			2			—			—			1
Net curtailment loss (gain)(a)	—			—			—			—			(5		)	4			—			—			(7		)
Net settlement loss(b)	28			4			97			6			119			—			—			—			—
Net periodic benefit cost(c)	$	48		$	(8	)	$	124		$	(5	)	$	153		$	9		$	3		$	10		$	4
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	28		$	(26	)	$	70		$	41		$	30		$	(25	)	$	5		$	11		$	(21	)
Amortization of actuarial gain (loss)	(36		)	(4		)	(111		)	(6		)	(134		)	(2		)	—			—			(1		)
Prior service cost (credit)	—			—			—			1			(89		)	1			—			(38		)	—
Amortization of prior service credit (cost)	10			—			10			(1		)	7			(5		)	7			3			13
Total recognized in other comprehensive (income) loss	$	2		$	(30	)	$	(31	)	$	35		$	(186	)	$	(31	)	$	12		$	(24	)	$	(9	)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	50		$	(38	)	$	93		$	30		$	(33	)	$	(22	)	$	15		$	(14	)	$	(5	)

^(a)  Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.

^(b)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.

^(c)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are $13 million and $10 million. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are $1 million and $7 million.

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2017, 2016 and 2015.

	Pension Benefits												Other Benefits
	2017				2016				2015				2017		2016		2015
(In millions)	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		U.S.		U.S.
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.55	%	2.50	%	4.02	%	2.70	%	4.04	%	3.90	%	3.54	%	3.98	%	4.36	%
Rate of compensation increase (a)	4.00	%	—		4.00	%	—		4.00	%	—		4.00	%	4.00	%	4.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.86	%	2.70	%	3.66	%	3.90	%	3.79	%	3.70	%	3.98	%	4.36	%	3.93	%
Expected long-term return on plan assets	6.50	%	4.50	%	6.75	%	5.50	%	6.75	%	5.70	%	—		—		—
Rate of compensation increase (a)	4.00	%	—		4.00	%	—	%	4.00	%	3.60	%	4.00	%	4.00	%	4.00	%

^(a)  No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.

91

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Expected long-term return on plan assets – The expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group which utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation. To determine the expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation to develop the overall expected long-term return on plan assets assumption.

Assumed weighted average health care cost trend rates

	2017		2016		2015
Initial health care trend rate	8.00	%	8.25	%	8.00	%
Ultimate trend rate	4.70	%	4.50	%	4.50	%
Year ultimate trend rate is reached	2025		2025		2024

Employer provided subsidies for post-65 retiree health care coverage were frozen effective January 1, 2017 at January 1, 2016 established amount levels. Company contributions are funded to a Health Reimbursement Account on the retiree’s behalf to subsidize the retiree’s cost of obtaining health care benefits through a private exchange. Therefore, a 1% change in health care cost trend rates would not have a material impact on either the service and interest cost components and the postretirement benefit obligations.

Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with applicable legal requirements; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plan's investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

U.S. plan – The plan’s current targeted asset allocation is comprised of 55% equity securities and 45% other fixed income securities. Over time, as the plan’s funded ratio (as defined by the investment policy) improves, in order to reduce volatility in returns and to better match the plan’s liabilities, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. The plan's assets are managed by a third-party investment manager.

International plan – Our international plan's target asset allocation is comprised of 55% equity securities and 45% fixed income securities. The plan assets are invested in ten separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers whose performance is measured independently by a third-party asset servicing consulting firm.

Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2017 and 2016.

Cash and cash equivalents – Cash and cash equivalents are valued using a market approach and are considered Level 1. This investment also includes a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2.

Equity securities -Investments in common stock and preferred stock are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership. These private equity investments are considered Level 3. Investments in pooled funds are valued using a market approach at the net asset value ("NAV") of units held. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Fixed income securities - Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds ("ETFs") are valued at the closing price reported in an active market and are considered Level 1. Corporate bonds, non-U.S. government bonds, private placements, taxable municipals, GNMA/FNMA pools, and Yankee bonds are valued using calculated yield curves created by models that incorporate various market factors. Primarily investments are held in U.S. and non-U.S. corporate bonds in diverse industries and are considered Level 2. Other fixed income investments include futures contracts, real estate investment trusts, credit default, zero coupon, and interest rate swaps. The investment in the commingled

92

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

funds is valued using the NAV of units held as a practical expedient. The commingled funds consist of equity and fixed income portfolios with underlying investments held in U.S. and non-U.S. securities. Pooled funds primarily have investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds and are considered Level 2.

Other – Other investments are comprised of an unallocated annuity contract, two limited liability companies, real estate and U.S. treasury futures. All are considered Level 3, as significant inputs to determine fair value are unobservable.

The following tables present the fair values of our defined benefit pension plan's assets, by level within the fair value hierarchy, as of December 31, 2017 and 2016.

	December 31, 2017
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	6	$	1	$	—	$	—	$	—	$	—	$	6	$	1
Equity securities:
Common stock	81		—		—		—		—		—		81		—
Private equity	—		—		—		—		16		—		16		—
Mutual and pooled funds	—		151		—		115		—		—		—		266
Fixed income securities:
Corporate	—		—		6		—		—		—		6		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	19		—		2		—		3		—		24		—
Pooled funds	—		—		—		403		—		—		—		403
Other	—		—		—		—		19		—		19		—
Total investments, at fair value	111		152		8		518		38		—		157		670
Commingled funds (a)	—		—		—		—		—		—		59		—
Total investments	$	111	$	152	$	8	$	518	$	38	$	—	$	216	$	670

	December 31, 2016
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	8	$	5	$	—	$	—	$	—	$	—	$	8	$	5
Equity securities:
Common stock	82		—		—		—		—		—		82		—
Private equity	—		—		—		—		20		—		20		—
Mutual and pooled funds	—		201		—		159		—		—		—		360
Fixed income securities:
Corporate	—		—		52		—		—		—		52		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	6		—		19		—		—		—		25		—
Pooled funds	—		—		—		230		—		—		—		230
Other	—		—		—		—		21		—		21		—
Total investments, at fair value	101		206		71		389		41		—		213		595
Commingled funds (a)	—		—		—		—		—		—		14		—
Total investments	$	101	$	206	$	71	$	389	$	41	$	—	$	227	$	595

^(a) After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update.

The activity during the year ended December 31, 2017 and 2016, for the assets using Level 3 fair value measurements was immaterial.

93

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Cash flows

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2017 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l		U.S.
2018	$	43	$	17	$	21
2019	40		18		20
2020	37		17		20
2021	33		19		19
2022	30		21		18
2023 through 2027	123		118		74

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $65 millionin 2018. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $21 million in 2018.

Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $20 million, $20 million and $20 million in 2017, 2016 and 2015.

18.  Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:

	Year Ended December 31,
(In millions)	2017			2016			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(9	)	$	(14	)	General and administrative
Net settlement loss	(32		)	(103		)	General and administrative
Derivative hedges
Recognized gain on terminated derivative hedge	46			—			Net interest and other
Ineffective portion of derivative hedge	1			4			Net interest and other
	6			(113		)	Income (loss) from operations
	(40		)	41			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	$	(34	)	$	(72	)	Income (loss) from continuing operations
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	(30		)	—			Income (loss) from discontinued operations
Total reclassifications to expense	$	(64	)	$	(72	)

19. Supplemental Cash Flow Information

	Year Ended December 31,
(In millions)	2017			2016			2015
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(379	)	$	(375	)	$	(325	)
Income taxes paid to taxing authorities  (a)	(391		)	(84		)	(171		)
Noncash investing activities, related to continuing operations:
Changes in asset retirement costs	$	(202	)	$	110		$	(95	)
Asset retirement obligations assumed by buyer	14			40			251
Increase in capital expenditure accrual	176			—			—
Notes receivable for disposition of assets	748			—			—

^(a) Includes a payment of $108 million made to U.K. taxing authorities to preserve our appeal rights, see Note 7 - Income Taxes for additional discussion.

20. Other Items

Net interest and other

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest:
Interest income	$	34		$	14		$	9
Interest expense	(380		)	(398		)	(350		)
Income on interest rate swaps	53			13			11
Interest capitalized	3			18			19
Total interest	(290		)	(353		)	(311		)
Other:
Net foreign currency gain (loss)	8			6			4
Other	12			15			21
Total other	20			21			25
Net interest and other	$	(270	)	$	(332	)	$	(286	)

Foreign currency – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

	Year Ended December 31,
(In millions)	2017		2016			2015
Net interest and other	$	8	$	6		$	4
Provision for income taxes	57		(32		)	(11		)
Aggregate foreign currency gains (losses)	$	65	$	(26	)	$	(7	)

94

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

21. Equity Method Investments and Related Party Transactions

During 2017, 2016 and 2015 only our equity method investees were considered related parties and they included:

• EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.

•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.

• AMPCO, in which we have a 45% interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2017	2017		2016
EGHoldings	60%	$	456	$	550
Alba Plant LLC	52%	214		215
AMPCO	45%	177		165
Other investments		—		1
Total		$	847	$	931

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $276 million in 2017, $192 million in 2016 and $178 million in 2015.

Summarized financial information for equity method investees is as follows:

(In millions)	2017		2016		2015
Income data – year (a):
Revenues and other income	$	1,294	$	770	$	769
Income from operations	631		346		313
Net income	508		313		280
Balance sheet data – December 31:
Current assets	$	586	$	525
Noncurrent assets	1,044		1,173
Current liabilities	221		218
Noncurrent liabilities	94		47

^(a)  See Item 15 Exhibits, Financial Statement Schedules which contains the Alba Plant LLC audited financial statements, which have been included pursuant to Rule 3-09 of Regulation S-X.

Revenues from related parties were $60 million, $54 million and $51 million in 2017, 2016 and 2015, with the majority related to EGHoldings in all years. Purchases from related parties were $132 million, $103 million and $207 million in 2017, 2016 and 2015 with the majority related to Alba Plant LLC in all years.

Current receivables from related parties at December 31, 2017 and 2016, were $24 million, and $23 million. Payables to related parties were $14 million and $11 million at December 31, 2017 and 2016, with the majority related to Alba Plant LLC.

22. Stockholders’ Equity

In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Development Program.

There were no share repurchases during 2017 or 2016 under our publicly announced plans or programs. As of December 31, 2017 the total remaining share repurchase authorization was $1.5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables.

95

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

23. Leases

We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Operating Lease Obligations
2018	$	29
2019	28
2020	27
2021	26
2022	5
Later years	4
Sublease rentals	—
Total minimum lease payments	$	119

^* Future minimum commitments for capital lease obligations are nil as of December 31, 2017.

Operating lease rental expense related to continuing operations was $87 million, $87 million and $99 million in 2017, 2016 and 2015.

24. Commitments and Contingencies

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs, which we claimed for U.K. corporation tax purposes.  The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In the third quarter of 2017, a hearing took place at the U.K.’s First-tier Tribunal with respect to this tax deduction.  In the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the judge sided with the U.K. tax authorities with respect to the timing of the decommissioning cost deductions.  We intend to appeal this decision and estimate that any revisions to current and deferred tax liabilities, if we do not prevail in the appeals process, would have no cumulative adverse earnings impact on our consolidated results of operations.  In accordance with U.K. regulations, we have paid the amount of tax and interest in question, approximately $108 million, prior to our appeal.  As a result of the negative ruling we no longer consider this position to be more-likely-than-not to be sustained and have created an uncertain tax position related to the Brae area decommissioning costs.  The payment of the tax and interest to the U.K. tax authorities is not to settle the position, but a regulatory requirement to appeal in the U.K.  If we ultimately prevail in appeals, the U.K. tax authorities will refund the tax and interest, however, if we ultimately lose in appeals no material future payments related to this issue will be required.  See Note 7 for further detail.

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS.  These audits have been completed through the 2014 tax year, except for tax years 2010 and 2011. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the fourth quarter of 2017.  We believe that it is more likely than not that we will prevail.

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.

Environmental matters – We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of federal, state, local and foreign laws and regulations relating to the environment. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected.  We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

At December 31, 2017 and 2016, accrued liabilities for remediation were not material. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.

96

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Guarantees – We have entered into a performance guarantee related to asset retirement obligations with aggregate maximum potential undiscounted payments totaling $35 million as of December 31, 2017. Under the terms of this guarantee arrangement, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.

Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contract commitments – At December 31, 2017 and 2016, contractual commitments to acquire property, plant and equipment totaled $102 million and $144 million.

In connection with the sale of our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius and Neptune fields in the Gulf of Mexico, we retained an overriding royalty interest in the properties. As part of the sale agreement, proceeds associated with the production of our override, up to $70 million, are dedicated solely to the satisfaction of the corresponding future abandonment obligations of the properties. The term of our override ends once sales proceeds equal $70 million.

97

Select Quarterly Financial Data (Unaudited)

	2017												2016
(In millions, except per share data)	1st Qtr.			2nd Qtr.			3rd Qtr.			4th Qtr.			1st Qtr.			2nd Qtr.			3rd Qtr.			4th Qtr.
Revenues	$	988		$	993		$	1,162		$	1,230		$	612		$	761		$	861		$	936
Income (loss) from continuing operations before income taxes (a)	(16		)	(112		)	(458		)	132			(613		)	(192		)	(313		)	(46		)
Income (loss) from continuing operations	(50		)	(153		)	(599		)	(28		)	(360		)	(138		)	(206		)	(1,383		)
Discontinued operations (b)	(4,907		)	14			—			—			(47		)	(32		)	14			12
Net income (loss) (c)	$	(4,957	)	$	(139	)	$	(599	)	$	(28	)	$	(407	)	$	(170	)	$	(192	)	$	(1,371	)
Income (loss) per share:
Continuing operations	$	(0.06	)	$	(0.18	)	$	(0.70	)	$	(0.03	)	$	(0.49	)	$	(0.16	)	$	(0.24	)	$	(1.63	)
Discontinued operations (b)	$	(5.78	)	$	0.02		$	—		$	—		$	(0.07	)	$	(0.04	)	$	0.01		$	0.01
Basic net income (loss)	$	(5.84	)	$	(0.16	)	$	(0.70	)	$	(0.03	)	$	(0.56	)	$	(0.20	)	$	(0.23	)	$	(1.62	)
Dividends paid per share	$	0.05		$	0.05		$	0.05		$	0.05		$	0.05		$	0.05		$	0.05		$	0.05

^(a) Includes impairments to proved properties of $24 million and $201 million in the fourth and third quarter of 2017 and $47 million in the third quarter of 2016. Also includes unproved property impairments and exploratory dry well costs of $215 million in the third quarter of 2017 and $118 million in the second quarter of 2016. (See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements).

^(b) We closed on the sale of our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented. Included in the first quarter of 2017 is an after-tax non-cash impairment charge of $4.96 billion, primarily related to the property, plant, and equipment.

^(c) Includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million in the fourth quarter of 2016 (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).

98

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

The supplementary information is disclosed by the following geographic areas: the U.S.; E.G.; Libya; Other Africa, which includes Gabon; and Other International ("Other Int’l"), which includes the U.K. and the Kurdistan Region of Iraq. We closed the sale of our Canada business in 2017 and have reflected this business as discontinued operations ("Disc Ops") in all periods presented. See Note 5 for further details on our Canadian disposition.

Preparation of Reserve Estimates

All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGL, natural gas and our historical synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group ("CRG"), which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGLs and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are petro-technical professionals located throughout our organization who meet the qualifications we have established for employees engaged in estimating reserves and resources. QREs have the education, experience, and training necessary to estimate reserves and resources in a manner consistent with all external reserve estimation regulations and internal resource estimation directives and practices. QREs generally hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed our QRE training course. All reserves changes (including proved) must be approved by the CRG. Additionally, any change to proved reserve estimates in excess of 5 mmboe on a total field basis, within a single month, must be approved by the Director of Corporate Reserves.

The Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of New Mexico. In his 31 years with Marathon Oil, he has held numerous engineering and management positions, including more recently managing reservoir engineering and geoscience for our Eagle Ford development in South Texas. He is a 25 year member of the Society of Petroleum Engineers ("SPE").

Technologies used in proved reserves estimation includes statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, pressure gradient analysis, reservoir simulation and volumetric analysis. The observed statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved developed locations establish the reasonable certainty criteria required for booking proved reserves.

Historical estimates of synthetic crude oil reserves were prepared by GLJ Petroleum Consultants of Calgary, Alberta, Canada, third-party consultants for 2015. Their report was filed as an exhibit to the prior year Annual Report on Form 10-K. The individual responsible for the estimates of our synthetic crude oil reserves had 15 years of experience in petroleum engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional Engineer in the Province of Alberta.

Audits of Estimates

We engage third-party consultants to provide, at a minimum, independent estimates for fields that comprise 80% of our total proved reserves over a rolling four-year period. We exceeded this percentage for the four-year period ended December 31, 2017, with 84% of our total proved reserves independently audited. An audit tolerance at a field level of +/- 10% to our internal estimates has been established. Should the third-party consultants’ initial analysis fall outside our tolerance band, both parties will re-examine the information provided, request additional data and refine their analysis, if appropriate. In the very limited instances where differences outside the 10% tolerance cannot be resolved by year end, a plan to resolve the difference is developed and executive management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2017, 2016 or 2015.

During 2017, 2016 and 2015, Netherland, Sewell & Associates, Inc. prepared a reserves certification for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI. NSAI’s technical team members meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The senior technical advisor has over 13 years of practical experience in petroleum engineering and the estimation and evaluation of reserves and is a registered Professional Engineer in the State of Texas. The second team member has over 11 years of practical experience in petroleum geosciences and is a licensed Professional Geoscientist in the State of Texas.

Ryder Scott Company also performed audits of the prior years' reserves for several of our fields in 2017, 2016 and 2015. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 35 years of industry experience, having worked for a major financial advisory services group before joining Ryder Scott. He is a 26 year member of SPE and is a registered Professional Engineer in the State of Texas.

99

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves

The estimation of net recoverable quantities of crude oil and condensate, natural gas liquids, natural gas and our historical synthetic crude oil is a highly technical process which is based upon several underlying assumptions that are subject to change. Proved reserves are determined using "SEC Pricing", calculated as an unweighted arithmetic average of the first-day-of-the-month closing price for each month. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Critical Accounting Estimates – Estimated Quantities of Net Reserves for the table providing our 2017 SEC pricing of benchmark prices and the underlying assumptions used.

The table below provides the 2017 SEC pricing for certain benchmark prices:

	SEC Pricing 2017
WTI Crude oil (per bbl)	$	51.34
Henry Hub natural gas (per mmbtu)	$	2.98
Brent crude oil (per bbl)	$	54.39
Mont Belvieu NGLs (per bbl)	$	22.03

100

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves

(mmbbl)	U.S.		E.G.(a)		Libya		Other Int'l		Cont Ops		Disc Ops	Total
Crude oil and condensate
Proved developed and undeveloped reserves:
Beginning of year - 2015	634		57		208		29		928		—	928
Revisions of previous estimates	(57	)	2		(7	)	(2	)	(64	)	—	(64	)
Improved recovery	1		—		—		—		1		—	1
Purchases of reserves in place	—		—		—		—		—		—	—
Extensions, discoveries and
other additions	70		—		—		—		70		—	70
Production	(62	)	(7	)	—		(5	)	(74	)	—	(74	)
Sales of reserves in place	(6	)	—		—		—		(6	)	—	(6	)
End of year - 2015	580		52		201		22		855		—	855
Revisions of previous estimates	55		1		(28	)	3		31		—	31
Improved recovery	4		—		—		—		4		—	4
Purchases of reserves in place	12		—		—		—		12		—	12
Extensions, discoveries and
other additions	37		—		—		1		38		—	38
Production	(48	)	(8	)	(1	)	(4	)	(61	)	—	(61	)
Sales of reserves in place	(77	)	—		—		—		(77	)	—	(77	)
End of year - 2016	563		45		172		22		802		—	802
Revisions of previous estimates	9		(2	)	—		8		15		—	15
Improved recovery	—		—		—		—		—		—	—
Purchases of reserves in place	18		—		—		—		18		—	18
Extensions, discoveries and
other additions	30		4		—		—		34		—	34
Production	(49	)	(8	)	(7	)	(4	)	(68	)	—	(68	)
Sales of reserves in place	(1	)	—		—		—		(1	)	—	(1	)
End of year - 2017	570		39		165		26		800		—	800
Proved developed reserves:
Beginning of year - 2015	294		30		175		19		518		—	518
End of year - 2015	327		25		173		16		541		—	541
End of year - 2016	238		45		172		13		468		—	468
End of year - 2017	263		39		165		17		484		—	484
Proved undeveloped reserves:
Beginning of year - 2015	340		27		33		10		410		—	410
End of year - 2015	253		27		28		6		314		—	314
End of year - 2016	325		—		—		9		334		—	334
End of year - 2017	307		—		—		9		316		—	316

101

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(mmbbl)	U.S.		E.G.(a)		Libya	Other Int'l		Cont Ops		Disc Ops	Total
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of year - 2015	161		30		—	1		192		—	192
Revisions of previous estimates	(7	)	2		—	(1	)	(6	)	—	(6	)
Improved recovery	—		—		—	—		—		—	—
Purchases of reserves in place	—		—		—	—		—		—	—
Extensions, discoveries and
other additions	33		—		—	—		33		—	33
Production	(14	)	(4	)	—	—		(18	)	—	(18	)
Sales of reserves in place	(1	)	—		—	—		(1	)	—	(1	)
End of year - 2015	172		28		—	—		200		—	200
Revisions of previous estimates	(8	)	—		—	—		(8	)	—	(8	)
Improved recovery	—		—		—	—		—		—	—
Purchases of reserves in place	12		—		—	—		12		—	12
Extensions, discoveries and
other additions	11		—		—	—		11		—	11
Production	(14	)	(4	)	—	—		(18	)	—	(18	)
Sales of reserves in place	(3	)	—		—	—		(3	)	—	(3	)
End of year - 2016	170		24		—	—		194		—	194
Revisions of previous estimates	37		3		—	—		40		—	40
Improved recovery	—		—		—	—		—		—	—
Purchases of reserves in place	5		—		—	—		5		—	5
Extensions, discoveries and
other additions	34		2		—	—		36		—	36
Production	(16	)	(4	)	—	—		(20	)	—	(20	)
Sales of reserves in place	(1	)	—		—	—		(1	)	—	(1	)
End of year - 2017	229		25		—	—		254		—	254
Proved developed reserves:
Beginning of year - 2015	68		15		—	—		83		—	83
End of year - 2015	92		12		—	—		104		—	104
End of year - 2016	78		24		—	—		102		—	102
End of year - 2017	118		25		—	—		143		—	143
Proved undeveloped reserves:
Beginning of year - 2015	93		15		—	1		109		—	109
End of year - 2015	80		16		—	—		96		—	96
End of year - 2016	92		—		—	—		92		—	92
End of year - 2017	111		—		—	—		111		—	111

102

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(bcf)	U.S.		E.G.(a)		Libya		Other Int'l		Cont Ops		Disc Ops	Total
Natural gas
Proved developed and undeveloped reserves:
Beginning of year - 2015	1,144		1,205		209		22		2,580		—	2,580
Revisions of previous estimates	(22	)	35		(3	)	1		11		—	11
Improved recovery	—		—		—		—		—		—	—
Purchases of reserves in place	1		—		—		—		1		—	1
Extensions, discoveries and
other additions	225		—		—		—		225		—	225
Production (b)	(128	)	(150	)	—		(8	)	(286	)	—	(286	)
Sales of reserves in place	(69	)	—		—		—		(69	)	—	(69	)
End of year - 2015	1,151		1,090		206		15		2,462		—	2,462
Revisions of previous estimates	145		8		(1	)	3		155		—	155
Improved recovery	—		—		—		—		—		—	—
Purchases of reserves in place	61		—		—		—		61		—	61
Extensions, discoveries and
other additions	71		—		—		—		71		—	71
Production (b)	(115	)	(155	)	—		(8	)	(278	)	—	(278	)
Sales of reserves in place	(25	)	—		—		—		(25	)	—	(25	)
End of year - 2016	1,288		943		205		10		2,446		—	2,446
Revisions of previous estimates	(33	)	(18	)	—		4		(47	)	—	(47	)
Improved recovery	—		—		—		—		—		—	—
Purchases of reserves in place	36		—		—		—		36		—	36
Extensions, discoveries and
other additions	204		76		—		—		280		—	280
Production (b)	(127	)	(168	)	(1	)	(6	)	(302	)	—	(302	)
Sales of reserves in place	(44	)	—		—		—		(44	)	—	(44	)
End of year - 2017	1,324		833		204		8		2,369		—	2,369
Proved developed reserves:
Beginning of year - 2015	575		664		94		17		1,350		—	1,350
End of year - 2015	640		552		94		11		1,297		—	1,297
End of year - 2016	648		943		95		5		1,691		—	1,691
End of year - 2017	726		833		94		2		1,655		—	1,655
Proved undeveloped reserves:
Beginning of year - 2015	569		541		115		5		1,230		—	1,230
End of year - 2015	511		538		112		4		1,165		—	1,165
End of year - 2016	640		—		110		5		755		—	755
End of year - 2017	598		—		110		6		714		—	714

103

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(mmbbl)	U.S.	E.G.(a)	Libya	Other Int'l	Cont Ops	Disc Ops		Total
Synthetic crude oil
Proved developed and undeveloped reserves:
Beginning of year - 2015	—	—	—	—	—	648		648
Revisions of previous estimates	—	—	—	—	—	67		67
Improved recovery	—	—	—	—	—	—		—
Purchases of reserves in place	—	—	—	—	—	—		—
Extensions, discoveries and
other additions	—	—	—	—	—	—		—
Production	—	—	—	—	—	(17	)	(17	)
Sales of reserves in place	—	—	—	—	—	—		—
End of year - 2015	—	—	—	—	—	698		698
Revisions of previous estimates	—	—	—	—	—	12		12
Improved recovery	—	—	—	—	—	—		—
Purchases of reserves in place	—	—	—	—	—	—		—
Extensions, discoveries and
other additions	—	—	—	—	—	—		—
Production	—	—	—	—	—	(18	)	(18	)
Sales of reserves in place	—	—	—	—	—	—		—
End of year - 2016	—	—	—	—	—	692		692
Revisions of previous estimates	—	—	—	—	—	—		—
Improved recovery	—	—	—	—	—	—		—
Purchases of reserves in place	—	—	—	—	—	—		—
Extensions, discoveries and
other additions	—	—	—	—	—	—		—
Production	—	—	—	—	—	(7	)	(7	)
Sales of reserves in place	—	—	—	—	—	(685	)	(685	)
End of year - 2017	—	—	—	—	—	—		—
Proved developed reserves:
Beginning of year - 2015	—	—	—	—	—	644		644
End of year - 2015	—	—	—	—	—	698		698
End of year - 2016	—	—	—	—	—	692		692
End of year - 2017	—	—	—	—	—	—		—
Proved undeveloped reserves:
Beginning of year - 2015	—	—	—	—	—	4		4
End of year - 2015	—	—	—	—	—	—		—
End of year - 2016	—	—	—	—	—	—		—
End of year - 2017	—	—	—	—	—	—		—

104

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(mmboe)	U.S.		E.G.(a)		Libya		Other Int'l		Cont Ops		Disc Ops		Total
Total Proved Reserves
Proved developed and undeveloped reserves:
Beginning of year - 2015	986		288		243		33		1,550		648		2,198
Revisions of previous estimates	(67	)	8		(8	)	(2	)	(69	)	67		(2	)
Improved recovery	1		—		—		—		1		—		1
Purchases of reserves in place	1		—		—		—		1		—		1
Extensions, discoveries and
other additions	139		1		—		—		140		—		140
Production (b)	(98	)	(36	)	—		(6	)	(140	)	(17	)	(157	)
Sales of reserves in place	(18	)	—		—		—		(18	)	—		(18	)
End of year - 2015	944		261		235		25		1,465		698		2,163
Revisions of previous estimates	73		2		(28	)	4		51		12		63
Improved recovery	4		—		—		—		4		—		4
Purchases of reserves in place	34		—		—		—		34		—		34
Extensions, discoveries and
other additions	59		—		—		1		60		—		60
Production (b)	(82	)	(37	)	(1	)	(6	)	(126	)	(18	)	(144	)
Sales of reserves in place	(84	)	—		—		—		(84	)	—		(84	)
End of year - 2016	948		226		206		24		1,404		692		2,096
Revisions of previous estimates	42		(1	)	—		8		49		—		49
Improved recovery	—		—		—		—		—		—		—
Purchases of reserves in place	28		—		—		—		28		—		28
Extensions, discoveries and
other additions	98		18		—		—		116		—		116
Production (b)	(86	)	(40	)	(7	)	(5	)	(138	)	(7	)	(145	)
Sales of reserves in place	(10	)	—		—		—		(10	)	(685	)	(695	)
End of year - 2017	1,020		203		199		27		1,449		—		1,449
Proved developed reserves:
Beginning of year - 2015	458		155		191		22		826		644		1,470
End of year - 2015	526		129		189		18		862		698		1,560
End of year - 2016	424		226		188		14		852		692		1,544
End of year - 2017	502		203		181		17		903		—		903
Proved undeveloped reserves:
Beginning of year - 2015	528		133		52		11		724		4		728
End of year - 2015	418		132		46		7		603		—		603
End of year - 2016	524		—		18		10		552		—		552
End of year - 2017	518		—		18		10		546		—		546

^(a)  Consists of estimated reserves from properties governed by production sharing contracts.

^(b)  Excludes the resale of purchased natural gas used in reservoir management.

105

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

2017 proved reserves decreased by 647 mmboe primarily due to the following:

• Revisions of previous estimates: Increased by 49 mmboe primarily due to the acceleration of higher economic wells in the Bakken into the 5-year plan resulting in an increase of 44 mmboe, with the remainder being due to revisions across the business.

• Extensions, discoveries, and other additions: Increased by 116 mmboe primarily due to an increase of 97 mmboe associated with the expansion of proved areas and wells to sales from unproved categories in Oklahoma.

• Purchases of reserves in place: Increased by 28 mmboe from acquisitions of assets in the Northern Delaware Basin in New Mexico.

• Production: Decreased by 145 mmboe.

• Sales of reserves in place: Decreased by 695 mmboe including 685 mmboe associated with the sale of our Canadian business and 10 mmboe associated with divestitures of certain conventional assets in Oklahoma and Colorado. See Item 8. Financial Statements and Supplementary Data - Note 5 to the consolidated financial statements for information regarding these dispositions.

2016 proved reserves decreased by 67 mmboe primarily due to the following:

• Revisions of previous estimates: Increased by 63 mmboe primarily due to an increase of 151 mmboe associated with the acceleration of higher economic wells in the U.S. resource plays into the 5-year plan and a decrease of 64 mmboe due to U.S. technical revisions.

• Extensions, discoveries, and other additions: Increased by 60 mmboe primarily associated with the expansion of proved areas and new wells to sales from unproven categories in Oklahoma.

• Purchases of reserves in place: Increased by 34 mmboe from acquisition of STACK assets in Oklahoma.

• Production: Decreased by 144 mmboe.

• Sales of reserves in place: Decreased by 84 mmboe associated with the divestitures of certain Wyoming and Gulf of Mexico assets.

2015 proved reserves decreased by 35 mmboe primarily due to the following:

• Revisions of previous estimates: Decreased by 2 mmboe primarily resulting from an increase of 105 mmboe associated with drilling programs in U.S. resource plays and an increase of 67 mmboe in discontinued operations due to technical reevaluation and lower royalty percentages related to lower realized prices, offset by a decrease of 173 mmboe which was largely due to reductions to our capital development program and adherence to the SEC 5-year rule.

• Extensions, discoveries, and other additions: Increased by140 mmboe as a result of drilling programs in our U.S. resource plays.

• Production: Decreased by 157 mmboe.

• Sales of reserves in place: U.S. conventional assets sales contributed to a decrease of 18 mmboe.

Changes in Proved Undeveloped Reserves

As of December 31, 2017, 546 mmboe of proved undeveloped reserves were reported, a decrease of 6 mmboe from December 31, 2016. The following table shows changes in proved undeveloped reserves for 2017:

(mmboe)
Beginning of year	552
Revisions of previous estimates	5
Improved recovery	—
Purchases of reserves in place	15
Extensions, discoveries, and other additions	57
Dispositions	—
Transfers to proved developed	(83	)
End of year	546

Revisions of prior estimates. Revisions of prior estimates increased 5 mmboe during 2017, primarily due to a 44 mmboe increase in the Bakken from an acceleration of higher economic wells into the 5-year plan, offset by a decrease of 40 mmboe in Oklahoma due to the removal of less economic wells from the 5-year plan.

Extensions, discoveries and other additions. Increased 57 mmboe through expansion of proved areas in Oklahoma.

106

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Transfers to proved developed. 83 mmboe of PUD reserves were converted to proved developed status during 2017, primarily from assets in our U.S. resource plays. This 2017 transfer equates to a 15% PUD conversion rate and a 5-year average annual PUD conversion rate during the 2013-2017 period of 18%. All proved undeveloped reserve drilling locations are scheduled to be drilled prior to the end of 2022.

A total of 25 mmboe of proved undeveloped reserves, or less than 2% of the company’s total proved reserves, have been on the books beyond 5 years as of year-end 2017.

As of year-end 2017, there were 18 mmboe of proved undeveloped reserves, initially disclosed in 2012, associated with the Faregh Phase II project in Libya. Drilling operations and construction of the associated gas plant were completed in 2010. Final commissioning was halted in 2011 and again in 2013 due to civil unrest and subsequent declaration of Force Majeure.  In 2017, teams conducted an assessment of the facilities to determine the state of the equipment and developed a plan to recommission the plant and initiate production in 2018, at which time, all associated proved undeveloped reserves will be transferred to proved developed.

As of year-end 2017, there were 7 mmboe of proved undeveloped reserves, initially disclosed in 2011, associated with the Fuel Gas Deficiency project in the U.K. The project includes the design, procurement and installation of the Brae Bravo gas by-pass, which will ensure continued operations at the existing Brae Alpha and East Brae platforms. The project has been approved and work is underway with completion expected in 2018, at which time, all associated proved undeveloped reserves will be transferred to proved developed.

Costs Incurred & Future Costs to Develop

Costs incurred in 2017, 2016 and 2015 relating to the development of proved undeveloped reserves were $842 million, $359 million and $1,415 million. As of December 31, 2017, future development costs estimated to be required for the development of proved undeveloped crude oil and condensate, NGLs and natural gas reserves for the years 2018 through 2022 are projected to be $1,425 million, $1,348 million, $1,409 million, $1,458 million and $1,028 million.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

	Year Ended December 31,
(In millions)	U.S.		E.G.		Libya		Other Africa		Other Int'l		Total
2017 Capitalized Costs:
Proved properties	$	27,477	$	1,990	830		$	—	$	5,050	$	35,347
Unproved properties	2,755		110		217		43		33		3,158
Total	30,232		2,100		1,047		43		5,083		38,505
Accumulated depreciation,
depletion and amortization:
Proved properties	14,254		1,348		289		—		4,850		20,741
Unproved properties (a)	206		—		—		43		33		282
Total	14,460		1,348		289		43		4,883		21,023
Net capitalized costs	$	15,772	$	752	$	758	$	—	$	200	$	17,482
2016 Capitalized Costs:
Proved properties	$	25,497	$	1,978	$	756	$	—	$	5,864	$	34,095
Unproved properties	1,473		119		281		136		183		2,192
Total	26,970		2,097		1,037		136		6,047		36,287
Accumulated depreciation,
depletion and amortization:
Proved properties	12,526		1,216		268		1		5,246		19,257
Unproved properties (a)	382		2		—		—		113		497
Total	12,908		1,218		268		1		5,359		19,754
Net capitalized costs	$	14,062	$	879	$	769	$	135	$	688	$	16,533

^(a) Includes unproved property impairments (see Note 10).

107

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Costs Incurred for Property Acquisition, Exploration and Development ^(a) 

(In millions)	U.S.		E.G.		Libya		Other Africa		Other Int'l				Cont Ops		Disc Ops		Total
December 31, 2017
Property acquisition:
Proved	$	191	$	1	$	—	$	—	$	—			$	192	$	—	$	192
Unproved	1,746		—		—		1		—				1,747		—		1,747
Exploration	882		1		—		37		3				923		—		923
Development	1,122		5		10		—		(144		)	(b)	993		6		999
Total	$	3,941	$	7	$	10	$	38	$	(141	)		$	3,855	$	6	$	3,861
December 31, 2016
Property acquisition:
Proved	$	276	$	—	$	—	$	—	$	—			$	276	$	—	$	276
Unproved	642		—		—		1		(11		)		632		—		632
Exploration	525		1		—		10		3				539		—		539
Development	456		55		3		—		121			(b)	635		31		666
Total	$	1,899	$	56	$	3	$	11	$	113			$	2,082	$	31	$	2,113
December 31, 2015
Property acquisition:
Proved	$	4	$	—	$	—	$	—	$	—			$	4	$	—	$	4
Unproved	61		—		—		1		—				62		—		62
Exploration	959		60		1		37		50				1,107		1		1,108
Development	1,477		150		13		—		31				1,671		—		1,671
Total	$	2,501	$	210	$	14	$	38	$	81			$	2,844	$	1	$	2,845

^(a)  Includes costs incurred whether capitalized or expensed. 

^(b)  Includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.

108

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Results of Operations for Oil and Gas Producing Activities

	U.S.			E.G.			Libya			Other Africa			Other Int'l			Cont Ops			Disc Ops			Total
Year Ended December 31, 2017
Revenues and other income:
Sales	$	3,050		$	45		$	431		$	—		$	282		$	3,808		$	423		$	4,231
Transfers	—			344			—			—			—			344			—			344
Other income(a)	74			—			—			—			38			112			(43		)	69
Total revenues and other income	3,124			389			431			—			320			4,264			380			4,644
Expenses:
Production costs	(985		)	(84		)	(44		)	—			(152		)	(1,265		)	(272		)	(1,537		)
Exploration expenses(b)	(153		)	—			—			(171		)	(83		)	(407		)	—			(407		)
Depreciation, depletion and
amortization(c)	(2,105		)	(134		)	(21		)	—			(273		)	(2,533		)	(6,676		)	(9,209		)
Technical support and other	(28		)	(4		)	(4		)	(7		)	(18		)	(61		)	—			(61		)
Total expenses	(3,271		)	(222		)	(69		)	(178		)	(526		)	(4,266		)	(6,948		)	(11,214		)
Results before income taxes	(147		)	167			362			(178		)	(206		)	(2		)	(6,568		)	(6,570		)
Income tax provision	(1		)	(50		)	(333		)	—			13			(371		)	1,674			1,303
Results of operations	$	(148	)	$	117		$	29		$	(178	)	$	(193	)	$	(373	)	$	(4,894	)	$	(5,267	)
Year Ended December 31, 2016
Revenues and other income:
Sales	$	2,249		$	42		$	54		$	—		$	237		$	2,582		$	724		$	3,306
Transfers	—			291			—			—			—			291			—			291
Other income(a)	387			—			—			—			2			389			—			389
Total revenues and other income	2,636			333			54			—			239			3,262			724			3,986
Expenses:
Production costs	(952		)	(81		)	(36		)	—			(140		)	(1,209		)	(544		)	(1,753		)
Exploration expenses(b)	(306		)	(1		)	(6		)	(8		)	(2		)	(323		)	(7		)	(330		)
Depreciation, depletion and
amortization(c)	(1,901		)	(114		)	(7		)	—			(132		)	(2,154		)	(239		)	(2,393		)
Technical support and other	(21		)	(4		)	—			(3		)	(2		)	(30		)	(1		)	(31		)
Total expenses	(3,180		)	(200		)	(49		)	(11		)	(276		)	(3,716		)	(791		)	(4,507		)
Results before income taxes	(544		)	133			5			(11		)	(37		)	(454		)	(67		)	(521		)
Income tax provision (d)	195			(26		)	(2		)	—			57			224			15			239
Results of operations	$	(349	)	$	107		$	3		$	(11	)	$	20		$	(230	)	$	(52	)	$	(282	)
Year Ended December 31, 2015
Revenues and other income:
Sales	$	3,374		$	40		$	—		$	—		$	329		$	3,743		$	700		$	4,443
Transfers	—			296			—			—			—			296			—			296
Other income(a)	230			—			—			(109		)	1			122			—			122
Total revenues and other income	3,604			336			—			(109		)	330			4,161			700			4,861
Expenses:
Production costs	(1,259		)	(84		)	(31		)	—			(177		)	(1,551		)	(660		)	(2,211		)
Exploration expenses(b)	(750		)	(41		)	—			(36		)	(143		)	(970		)	(348		)	(1,318		)
Depreciation, depletion and
amortization(c)	(2,758		)	(92		)	(5		)	—			(163		)	(3,018		)	(266		)	(3,284		)
Technical support and other	(47		)	(6		)	(1		)	(1		)	(3		)	(58		)	(2		)	(60		)
Total expenses	(4,814		)	(223		)	(37		)	(37		)	(486		)	(5,597		)	(1,276		)	(6,873		)
Results before income taxes	(1,210		)	113			(37		)	(146		)	(156		)	(1,436		)	(576		)	(2,012		)
Income tax provision	437			(33		)	37			50			86			577			31			608
Results of operations	$	(773	)	$	80		$	—		$	(96	)	$	(70	)	$	(859	)	$	(545	)	$	(1,404	)

109

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

^(a)  Includes net gain (loss) on dispositions (see Note 5) and revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.

^(b)  Includes exploratory dry well costs, unproved property impairments, and other (see Note 10).

^(c)  Includes long-lived asset impairments (see Note 10).

^(d)    Discontinued operations activity includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase.

Results of Operations for Oil and Gas Producing Activities

The following reconciles results of operations for oil and gas producing activities to segment income:

	Year Ended December 31,
(In millions)	2017			2016			2015
Results of operations	$	(5,267	)	$	(282	)	$	(1,404	)
Discontinued operations	4,894			52			545
Results of continuing operations	(373		)	(230		)	(859		)
Items not included in results of oil and gas operations, net of tax:
Marketing income and other non-oil and gas producing related activities	(107		)	(39		)	(102		)
Income from equity method investments	229			142			127
Items not allocated to segment income, net of tax:
Loss (gain) on asset dispositions and other income	(79		)	(248		)	(76		)
Long-lived asset impairments	475			148			602
Unrealized loss (gain) on derivatives	81			72			(32		)
Deferred tax valuation allowance increase	—			(32		)	—
Segment income	$	226		$	(187	)	$	(340	)

110

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

U.S. GAAP prescribes guidelines for computing the standardized measure of future net cash flows and changes therein relating to estimated proved reserves, giving very specific assumptions to be made such as the use of a 10% discount rate and an unweighted average of commodity prices in the prior 12-month period using the closing prices on the first day of each month as well as current costs applicable at the date of the estimate. These and other required assumptions have not always proved accurate in the past, and other valid assumptions would give rise to substantially different results. In addition, the 10% discount rate required to be used is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the oil and natural gas industry in general. This information is not the fair value nor does it represent the expected present value of future cash flows of our crude oil and condensate, natural gas liquid, and natural gas reserves.

(In millions)	U.S.			E.G.			Libya			Other Int'l				Total
Year Ended December 31, 2017
Future cash inflows	$	36,480		$	1,966		$	10,303		$	1,403			$	50,152
Future production and support costs	(14,796		)	(748		)	(931		)	(821		)		(17,296		)
Future development costs	(6,987		)	(7		)	(501		)	(1,247		)		(8,742		)
Future income tax expenses	(786		)	(274		)	(8,387		)	496				(8,951		)
Future net cash flows	$	13,911		$	937		$	484		$	(169	)	(a)	$	15,163
10% annual discount for timing of cash flows	(7,009		)	(235		)	(224		)	168				(7,300		)
Standardized measure of discounted future net cash flows- related to continuing operations	$	6,902		$	702		$	260		$	(1	)		$	7,863
Standardized measure of discounted future net cash flows- related to discontinued operations														—
Year Ended December 31, 2016
Future cash inflows	$	27,610		$	1,977		$	8,511		$	921			$	39,019
Future production and support costs	(12,758		)	(824		)	(930		)	(673		)		(15,185		)
Future development costs	(7,233		)	(13		)	(296		)	(1,345		)		(8,887		)
Future income tax expenses	—			(251		)	(6,884		)	514				(6,621		)
Future net cash flows	$	7,619		$	889		$	401		$	(583	)	(a)	$	8,326
10% annual discount for timing of cash flows	(4,355		)	(264		)	(143		)	313				(4,449		)
Standardized measure of discounted future net cash flows- related to continuing operations	$	3,264		$	625		$	258		$	(270	)		$	3,877
Standardized measure of discounted future net cash flows- related to discontinued operations														$	1,076
Year Ended December 31, 2015
Future cash inflows	$	31,026		$	2,671		$	12,157		$	1,281			$	47,135
Future production and support costs	(12,270		)	(1,095		)	(901		)	(902		)		(15,168		)
Future development costs	(6,637		)	(94		)	(689		)	(1,537		)		(8,957		)
Future income tax expenses	(778		)	(369		)	(9,857		)	602				(10,402		)
Future net cash flows	$	11,341		$	1,113		$	710		$	(556	)	(a)	$	12,608
10% annual discount for timing of cash flows	(6,082		)	(380		)	(441		)	352				(6,551		)
Standardized measure of discounted future net cash flows- related to continuing operations	$	5,259		$	733		$	269		$	(204	)		$	6,057
Standardized measure of discounted future net cash flows- related to discontinued operations														$	165

^(a)  Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K.

111

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Changes in the Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
(In millions)	2017			2016				2015
Sales and transfers of oil and gas produced, net of production and support costs	$	(2,853	)	$	(1,634	)		$	(2,422	)
Net changes in prices and production and support costs related to future production	4,916			(3,621		)	(b)	(21,309		)	(b)
Extensions, discoveries and improved recovery, less related costs	661			(2,174		)		6
Development costs incurred during the period	1,027			669				1,693
Changes in estimated future development costs	183			2,534				7,247
Revisions of previous quantity estimates(a)	497			654				(5,682		)
Net changes in purchases and sales of minerals in place	102			(651		)		(460		)
Accretion of discount	698			1,005				2,719
Net change in income taxes	(1,245		)	1,038				9,989
Net change for the year	3,986			(2,180		)		(8,219		)
Beginning of the year related to continuing operations	3,877			6,057				14,276
End of the year related to continuing operations	$	7,863		$	3,877			$	6,057
Net change for the year related to discontinued operations	$	—		$	911			$	(2,115	)

^(a)  Includes amounts resulting from changes in the timing of production.

^(b)   Decrease primarily due to lower realized prices.

112

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2017.

Management's Annual Report on Internal Control Over Financial Reporting

See "Management’s Report on Internal Control over Financial Reporting" under Item 8 of this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

See "Report of Independent Registered Public Accounting Firm" under Item 8 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2017, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

113

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by this item is incorporated by reference to "Proposal 1: Election of Directors," "Corporate Governance—Committees of the Board" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our Proxy Statement for the 2018 Annual Meeting of Stockholders, to be filed with the SEC within 120 days of December 31, 2017 (the "2018 Proxy Statement").

See "Executive Officers of the Registrant" under Item 1 of this Form 10-K for information about our executive officers.

Our Code of Ethics for Senior Financial Officers, which applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, is available on our website at www.marathonoil.com under Investors—Corporate Governance. You may request a printed copy free of charge by sending a request to the Corporate Secretary. We intend to disclose any amendments and any waivers to our Code of Ethics for Senior Financial Officers on our website at www.marathonoil.com under Investors —Corporate Governance within four business days. The waiver information will remain on the website for at least 12 months after the initial disclosure of such waiver.

Item 11. Executive Compensation

Information required by this item is incorporated by reference to "Corporate Governance—Compensation Committee Interlocks and Insider Participation," "Compensation Committee Report," "Director Compensation," "Compensation Discussion and Analysis" and "Executive Compensation" in the 2018 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Portions of information required by this item are incorporated by reference to "Security Ownership of Certain Beneficial Owners and Management" in the 2018 Proxy Statement.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2017 with respect to shares of Marathon Oil common stock that may be issued under our existing equity compensation plans:

• Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan")

• Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") – No additional awards will be granted under this plan.

• Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan") – No additional awards will be granted under this plan.

• Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.

• Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights(c)	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by stockholders	11,915,472	(a)	$25.52	43,840,884	(d)
Equity compensation plans not approved by stockholders	12,291	(b)	N/A	—
Total	11,927,763		N/A	43,840,884

^(a)  Includes the following:

• 736,199 stock options outstanding under the 2016 Plan; 3,991,905 stock options outstanding under the 2012 Plan; 5,591,708 stock options outstanding under the 2007 Plan;

• 399,114 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan. Common stock units credited under the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan were 69,556, 142,724, 152,839 and 33,995, respectively;

114

• 1,196,546 restricted stock units granted to non-officers under the 2012 Plan and 2016 Plan and outstanding as of December 31, 2017.

• In addition to the awards reported above, 2,850,798 and 3,525,501 shares of restricted stock were issued and outstanding as of December 31, 2017, but subject to forfeiture restrictions under the 2012 and 2016 Plans, respectively.

^(b)  Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units.

^(c)  The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.

^(d)  Reflects the shares available for issuance under the 2016 Plan. No more than 18,496,714 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance.

The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003. Under the Deferred Compensation Plan for Non-Employee Directors, all non-employee directors were required to defer half of their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of common stock units equal to half of his or her annual retainer divided by the fair market value of our common stock on that date. The ongoing value of each common stock unit equals the market price of a share of our common stock. When the non-employee director leaves the Board, he or she is issued actual shares of our common stock equal to the number of common stock units in his or her account at that time.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this item is incorporated by reference to "Transactions with Related Persons," and "Proposal 1: Election of Directors—Director Independence" in the 2018 Proxy Statement.

Item 14. Principal Accountant Fees and Services

Information required by this item is incorporated by reference to "Proposal 2: Ratification of Independent Auditor for 2018" in the 2018 Proxy Statement.

115

PART IV

Item 15. Exhibits, Financial Statement Schedules

A. Documents Filed as Part of the Report

1. Financial Statements – See Part II, Item 8. of this Annual Report on Form 10-K.

2. Financial Statement Schedules – The audited financial statements and related footnotes of Alba Plant LLC, our equity method investment, are being filed within Exhibit 99.9 in accordance with Rule 3-09 of Regulation S-X. All other financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.

3. Exhibits – The information required by this Item 15 is incorporated by reference to the Exhibit Index accompanying this Annual Report on Form 10-K.

Item 16. Form 10-K Summary

None.

116

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 22, 2018	MARATHON OIL CORPORATION
	By:    /s/ GARY E. WILSON
	Gary E. Wilson
	Vice President, Controller and Chief Accounting Officer

POWER OF ATTORNEY

Each person whose signature appears below appoints Lee M. Tillman, Dane E. Whitehead, and Gary E. Wilson, and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, with full power and authority to each of said attorneys-in-fact and agents to do and perform each and every act whatsoever that is necessary, appropriate or advisable in connection with any or all of the above-described matters and to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 22, 2018 on behalf of the registrant and in the capacities indicated.

Signature	Title
/S/ LEE M. TILLMAN	President and Chief Executive Officer and Director
Lee M. Tillman
/S/ Dane E. Whitehead	Executive Vice President and Chief Financial Officer
Dane E. Whitehead
/s/ GARY E. WILSON	Vice President, Controller and Chief Accounting Officer
Gary E. Wilson
/S/ DENNIS H. REILLEY	Chairman of the Board
Dennis H. Reilley
/s/ GAURDIE E. BANISTER, JR.	Director
Gaurdie E. Banister, Jr.
/S/ GREGORY H. BOYCE	Director
Gregory H. Boyce
/S/ CHADWICK C. DEATON	Director
Chadwick C. Deaton
/S/ MARCELA E. DONADIO	Director
Marcela E. Donadio
/S/ PHILIP LADER	Director
Philip Lader
/S/ MICHAEL E. J. PHELPS	Director
Michael E. J. Phelps

117

Exhibit Index

Exhibit		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Number	Exhibit Description	Form	Exhibit	Filing Date
1	Underwriting Agreement
1.1*	Bond Purchase Agreement, dated as of November 28, 2017, between Marathon Oil Corporation, the Parish of St. John the Baptist, State of Louisiana, and Morgan Stanley & Co. LLC.
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1	Share Purchase Agreement, dated as of March 8, 2017, by and among Marathon Oil Dutch Holdings B.V., as Seller, and 10084751 Canada Limited, as a Buyer and Canadian Natural Resources Limited, as a Buyer, in respect of Marathon Oil Canada Corporation.	10-Q	10.1	5/5/2017
3	Articles of Incorporation and By-laws
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013
3.2	Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)	8-K	3.1	3/1/2016
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request	10-K	4.2	2/28/2014
10	Material Contracts
10.1	Amended and Restated Credit Agreement, dated as of May 28, 2014, among Marathon Oil Corporation, as borrower, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein	8-K	4.1	6/2/2014
10.2	First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein	10-Q	10.1	5/7/2015
10.3	Incremental Commitments Supplement, dated as of March 4, 2016, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.	8-K	99.1	3/8/2016

1

Exhibit		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Number	Exhibit Description	Form	Exhibit	Filing Date
10.4	Second Amendment, dated as of June 22, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, and supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.	8-K	99.1	6/23/2017
10.5	Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.	10-Q	10.2	8/3/2017
10.6†	Marathon Oil Corporation 2016 Incentive Compensation Plan	DEF 14A	App. A	4/7/2016
10.7†	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting)	8-K/A	10.1	10/6/2016
10.8†	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting)	10-K	10.6	2/24/2017
10.9†	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers	10-K	10.7	2/24/2017
10.10†	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Directors (3-year cliff vesting)	10-K	10.8	2/24/2017
10.11†	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Canadian Directors (3-year cliff vesting)	10-K	10.9	2/24/2017
10.12*	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Performance Unit Award Agreement for Section 16 Officers
10.13*	Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Performance Unit Award Agreement for Officers
10.14†	Marathon Oil Corporation 2012 Incentive Compensation Plan	DEF 14A	App. III	3/8/2012
10.15†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Non-Qualified Stock Option Award Agreement	8-K	10.1	8/1/2014
10.16†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Performance Unit Award Agreement for Section 16 Officers	10-Q	10.1	5/7/2014
10.17†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Performance Unit Award Agreement for Section 16 Officers	10-Q	10.2	5/7/2014
10.18†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Initial CEO Option Grant Agreement	10-Q	10.1	11/6/2013

2

Exhibit		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Number	Exhibit Description	Form	Exhibit	Filing Date
10.19†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers (3-year prorata vesting)	10-K	10.5	2/22/2013
10.20†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers (3-year prorata vesting)	10-K	10.6	2/22/2013
10.21†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting)	10-K	10.7	2/22/2013
10.22†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year cliff vesting)	10-K	10.8	2/22/2013
10.23†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting)	10-K	10.9	2/22/2013
10.24†	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year prorata vesting)	10-K	10.10	2/22/2013
10.25†	Marathon Oil Corporation 2007 Incentive Compensation Plan	10-K	10.5	2/29/2012
10.26†	Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers	10-K	10.6	2/29/2012
10.27†	Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers	10-K	10.5	2/28/2011
10.28†	Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers	10-K	10.26	2/26/2010
10.29†	Marathon Oil Corporation 2003 Incentive Compensation Plan	10-K	10.9	2/26/2010
10.30†	Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of December 20, 2016)	10-K	10.29	2/24/2017
10.31†	Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011	10-K	10.32	2/29/2012
10.32†	Marathon Oil Company Excess Benefit Plan Amended and Restated	10-K	10.31	2/29/2012
10.33†*	Marathon Oil Corporation Officer Change in Control Severance Benefits Plan (as amended, effective January 1, 2018)
10.34†	Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts	10-K	10.10	2/28/2011
10.35†	Marathon Oil Corporation Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009	10-K	10.32	2/27/2009
10.36	Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC	8-K	10.1	5/26/2011
12.1*	Computation of Ratio of Earnings to Fixed Charges
21.1*	List of Significant Subsidiaries
23.1*	Consent of Independent Registered Public Accounting Firm
23.2*	Consent of Independent Registered Public Accounting Firm
23.3*	Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists

3

Exhibit		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Number	Exhibit Description	Form	Exhibit	Filing Date
23.4*	Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists
23.5*	Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists
31.1*	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
31.2*	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
32.1*	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.1	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2015	10-K	99.1	2/25/2016
99.2*	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2016
99.3*	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2016
99.4*	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2016
99.5	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2016	10-K	99.3	2/24/2017
99.6	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2015	10-K	99.4	2/24/2017
99.7*	Summary report performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2016
99.8	Summary report performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2015	10-K	99.6	2/24/2017
99.9*	Alba Plant, LLC audited financial statements as of December 31, 2017
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase
101.LAB*	XBRL Taxonomy Extension Label Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
*	Filed herewith.
†	Management contract or compensatory plan or arrangement.

4

EX-1.1

Exhibit 1.1

BOND PURCHASE AGREEMENT

$1,000,000,000

Parish of St. John the Baptist, State of Louisiana

Revenue Refunding Bonds (Marathon Oil Corporation Project)
Series 2017

This BOND PURCHASE AGREEMENT, dated November 28, 2017, is by and among the Parish of St. John the Baptist, State of Louisiana (the “Issuer”), Morgan Stanley & Co. LLC (the “Underwriter”), and Marathon Oil Corporation (the “Corporation”).

1.Background.

(a)The Issuer and the Corporation propose to enter into a Refunding Agreement to be dated as of December 1, 2017 (the “Agreement”) pursuant to which the Issuer will finance the costs of the refunding of $1,000,000,000 aggregate principal amount of the Issuer’s outstanding 5.125% Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A (the “Prior Bonds”) on or about December 18, 2017 (the “Refunding Date”). The Prior Bonds were issued for the purpose of acquiring, constructing and equipping a project consisting of an expansion to an existing oil refinery and related facilities constituting nonresidential real property (including fixed improvements associated with such property) in the Parish of St. John the Baptist, Louisiana, then owned and operated by the Corporation. In order to finance a portion of the costs of refunding the Prior Bonds, the Issuer will issue and sell its Revenue Refunding Bonds (Marathon Oil Corporation Project) Series 2017 (the “Bonds”) in the original principal amount of $1,000,000,000 to the Underwriter, who will in turn offer the Bonds to the Corporation or an affiliate thereof at a price of par. By signing below, the Corporation agrees to purchase such Bonds from the Underwriter subject to the conditions set forth herein. The Bonds will contain the terms and provisions as are described in the final Official Statement and set forth in the Indenture referred to below, which terms and provisions have been approved by the Corporation. The Bonds shall mature and bear interest at the rate and be subject to redemption and optional and mandatory tender all as specified in Schedule 1 attached hereto.

(b)To induce the Underwriter to enter into this Bond Purchase Agreement and to sell and buy the Bonds, the Corporation has joined in this Bond Purchase Agreement. The Corporation acknowledges that the Issuer will sell the Bonds to the Underwriter and the Underwriter is making an offering thereof in reliance upon the representations, covenants and indemnity of the Corporation in this Bond Purchase Agreement.

(c)Inasmuch as this purchase and sale represents a negotiated transaction, the Issuer and the Corporation acknowledge and agree that: (i) the transaction contemplated by this Bond Purchase Agreement is an arm's length, commercial transaction among the Issuer, the Corporation and the Underwriter in which the Underwriter is acting solely as a principal and is not acting as a municipal advisor, financial advisor or fiduciary to the Issuer or the Corporation; (ii) the Underwriter has not assumed any advisory or fiduciary responsibility to the

Issuer or the Corporation with respect to the transaction contemplated hereby and the discussions, undertakings and procedures leading thereto (irrespective of whether the Underwriter has provided other services or is currently providing other services to the Issuer or the Corporation on other matters); (iii) the Underwriter is acting solely in its capacity as underwriter for its own account; (iv) the only obligations the Underwriter has to the Issuer and the Corporation with respect to the transaction contemplated hereby expressly are set forth in this Bond Purchase Agreement; and (v) the Issuer and the Corporation have consulted their own legal, accounting, tax, financial and other advisors, as applicable, to the extent they have deemed appropriate.

(d)The Bonds will be issued under a Trust Indenture to be dated as of December 1, 2017 (the “Indenture”) between the Issuer and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), pursuant to resolutions and ordinances adopted by the Issuer on October 10, 2017, October 24, 2017 and November 14, 2017 (collectively, the “Resolutions”). Under the Agreement, the Corporation will agree to make payments sufficient to pay the principal of and interest on the Bonds and the purchase price of Bonds tendered for purchase. The Issuer’s interest in the Agreement and payments thereunder (except certain rights of the Issuer to receive fees and expenses and indemnity thereunder) will be assigned by the Issuer to the Trustee as security for the payment of the principal of and interest on the Bonds. To assist the Underwriter in complying with Rule 15c2-12(b)(5) promulgated by the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Corporation will enter into a Continuing Disclosure Undertaking (the “CDU”).

2.Purchase, Sale and Closing. Upon the terms and conditions and in reliance on the representations, warranties, covenants and indemnity set forth herein, (a) the Underwriter agrees to purchase from the Issuer, and the Issuer agrees to sell to the Underwriter, the principal amount of Bonds for a purchase price of 100% of the principal amount thereof (being $1,000,000,000) and (b) the Corporation agrees to purchase from the Underwriter, and the Underwriter agrees to sell to the Corporation, the principal amount of the Bonds for a purchase price of $1,000,000,000. The Underwriter will be paid a fee of $150,000 for its services plus reimbursement of certain expenses hereunder. The purchase price of the Bonds shall be payable in immediately available funds to the Trustee. The Issuer will deliver or cause to be delivered to The Depository Trust Company, New York, New York (“DTC”) or to the Trustee as its agent, for the account of the Underwriter, duly executed and authenticated. Closing (“Closing”) for the delivery of the Bonds against payment therefor and delivery of documents and opinions will be at the offices of Foley & Judell, L.L.P. (“Bond Counsel”), at 9:00 a.m. local time on December 18, 2017, unless the Issuer and the Underwriter, with the approval of the Corporation, shall mutually agree on some other place, time or day. The Bonds shall initially be registered in the name of Cede & Co., as nominee and registered owner for DTC, and will be made available to the Underwriter for inspection at least one business day before Closing.

3.Preliminary Official Statement; Amendment; Rule 15c2-12.

(a)The Issuer has provided the Underwriter with copies of its Preliminary Official Statement dated November 27, 2017, relating to the Bonds (the “Preliminary Official Statement”). As of its date, the Preliminary Official Statement is hereby “deemed final”

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by the Issuer for purposes of Rule 15c2-12(b)(1) adopted by the SEC. Within seven (7) business days after the execution of this Bond Purchase Agreement and, in any event, in sufficient time to accompany any customer confirmations requesting payment, the Issuer shall deliver to the Underwriter copies of the final form of the Official Statement (with only such changes therein as shall have been approved by the Underwriter), in such quantities as the Underwriter may reasonably request in order for the Underwriter to comply with the Rules of the Municipal Securities Rulemaking Board (the “MSRB”) and Rule 15c2-12(b)(4), executed by an authorized officer of the Issuer (which, as so amended and supplemented, is herein referred to as the “Official Statement”). The Issuer hereby ratifies and consents to the use of the Preliminary Official Statement by the Underwriter on or before the date hereof in connection with the offering of the Bonds and hereby authorizes the use by the Underwriter of the Indenture, the Agreement, the Official Statement and any amendments thereof or supplements thereto pursuant to this Section (and drafts, clearly marked as such, thereof prior to the availability of such documents in final form), and the information contained in any of the foregoing, in connection with the offering and sale of the Bonds. The Corporation hereby authorizes the Agreement and the Official Statement (and the information contained therein) to be used by the Underwriter in connection with the offering and sale of the Bonds.

(b)The Underwriter agrees to file a copy of the Official Statement with the MSRB at the earliest practicable date after the delivery of the Bonds and to provide the Issuer and the Corporation with written notice of such filing and the date of such filing; and written notice of the date which is the end of the underwriting period within the meaning of Rule 15c2-12. The Underwriter also agrees to file the Official Statement (with any required forms) with the MSRB or its designee pursuant to MSRB Rule G-32 within one (1) business day of delivery of the Bonds to the Underwriter; and take any and all other actions necessary to comply with applicable SEC and MSRB rules governing the offering, sale and delivery of the Bonds to ultimate purchasers. Unless otherwise notified in writing by the Underwriter at or prior to the Closing, the Issuer and the Corporation can assume that the “end of the underwriting period” for purposes of Rule 15c2-12 shall be the Closing. The “end of the underwriting period” as used in this Bond Purchase Agreement shall mean either the Closing or such later date as to which notice is given by the Underwriter.

4.Issue Price.

(a)The Underwriter agrees to assist the Issuer in establishing the issue price of the Bonds and shall execute and deliver to the Issuer at Closing an “issue price” or similar certificate substantially in the form attached hereto as Exhibit E together with the supporting pricing wires or equivalent communications, with modifications to such certificate as may be deemed appropriate or necessary, in the reasonable judgment of the Underwriter, the Issuer and Bond Counsel, to accurately reflect, as applicable, the sales price or prices or the initial offering price or prices to the public of the Bonds.

(b)The Issuer will treat the first price at which 10% of the only maturity of the Bonds (the “10% test”) is sold to the public as the issue price of that maturity (if different interest rates apply within a maturity, each separate CUSIP number within that maturity will be subject to the 10% test).

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(c)The Underwriter has offered the Bonds to the public on or before the date of this Bond Purchase Agreement at the offering price or prices (the “initial offering price”), or at the corresponding yield or yields, set forth in the Official Statement. Schedule 2 sets forth, as of the date of this Bond Purchase Agreement, the maturities, if any, of the Bonds for which the 10% test has not been satisfied and for which the Issuer and the Underwriter agree that the restrictions set forth in the next sentence shall apply, which will allow the Issuer to treat the initial offering price to the public of each such maturity as of the sale date as the issue price of that maturity (the “hold-the-offering-price rule”). So long as the hold-the-offering-price rule remains applicable to any maturity of the Bonds, the Underwriter will neither offer nor sell unsold Bonds of that maturity to any person at a price that is higher than the initial offering price to the public during the period starting on the sale date and ending on the earlier of the following:

(i)the close of the fifth (5th) business day after the sale date; or

(ii)the date on which the Underwriter has sold at least 10% of that maturity of the Bonds to the public at a price that is no higher than the initial offering price to the public.

The Underwriter shall promptly advise the Issuer when the Underwriter has sold 10% of that maturity of the Bonds to the public at a price that is no higher than the initial offering price to the public, if that occurs prior to the close of the fifth (5th) business day after the sale date.

The Issuer acknowledges that the Underwriter shall be solely liable for its failure to comply with its agreement regarding the hold the offering price rule.

(d)The Underwriter acknowledges that sales of any Bonds to any person that is a related party to it shall not constitute sales to the public for purposes of this section. Further, for purposes of this section:

(i)“public” means any person other than an underwriter or a related party, which for purposes hereof includes the Corporation,

(ii)“underwriter” means (A) any person that agrees pursuant to a written contract with the Issuer (or with the lead underwriter to form an underwriting syndicate) to participate in the initial sale of the Bonds to the public and (B) any person that agrees pursuant to a written contract directly or indirectly with a person described in clause (A) to participate in the initial sale of the Bonds to the public (including a member of a selling group or a party to a retail distribution agreement participating in the initial sale of the Bonds to the public),

(iii)a purchaser of any of the Bonds is a “related party” to an underwriter if the underwriter and the purchaser are subject, directly or indirectly, to (i) at least 50% common ownership of the voting power or the total value of their stock, if both entities are corporations (including direct ownership by one corporation of another), (ii) more than 50% common ownership of their capital interests or profits interests, if both entities are partnerships (including direct ownership by one partnership of another), or (iii) more than 50% common ownership of the value of the outstanding stock of the corporation or the capital interests or profit interests of the

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partnership, as applicable, if one entity is a corporation and the other entity is a partnership (including direct ownership of the applicable stock or interests by one entity of the other), and

(iv)“sale date” means the date of execution of this Bond Purchase Agreement by all parties.

5.Issuer’s Representations. The Issuer makes the following representations as of the date of this Bond Purchase Agreement, all of which will survive the purchase and offering of the Bonds:

(a)The representations and warranties of the Issuer contained in the Agreement are, and as of the date of the Closing will be, true and correct in all material respects.

(b)Both at the time of execution hereof and on the date of the Closing, the statements and information contained in the Official Statement under the heading “THE ISSUER” do not and will not omit any statement or information which is necessary to make the statements and information therein, in light of the circumstances under which they were made, not misleading in any material respect.

(c)The Issuer is and will be on the date of the Closing duly existing as a parish and political subdivision of the State of Louisiana (the “State”) organized pursuant to the laws of the State, and authorized to issue bonds pursuant to Chapter 14-A of Title 39 of the Louisiana Revised Statutes of 1950, as amended (the “Refunding Act”).

(d)When delivered to and paid for by the Underwriter at the Closing in accordance with the provisions of this Bond Purchase Agreement, the Bonds will have been duly authorized, executed, authenticated, issued and delivered and will constitute valid and binding special obligations of the Issuer in conformity with, and be entitled to the benefit and security of the Indenture.

(e)The Issuer has duly authorized the execution and delivery by it of the Indenture, the Agreement and this Bond Purchase Agreement.

(f)The Issuer has full legal right, power and authority to enter into the Indenture, the Agreement and this Bond Purchase Agreement, to issue the Bonds and to carry out and consummate all other transactions contemplated by the Indenture and the Agreement, and the Issuer has complied with the provisions of the Refunding Act in all matters relating to such transactions.

(g)No approval, permit, consent or authorization of any governmental or public agency, authority or person having jurisdiction over the Issuer not already obtained (other than any approvals that might be required to be obtained under the securities laws of any jurisdiction, as to which the Issuer makes no representations or warranties) is required in connection with the adoption of the Resolutions and the issuance and sale of the Bonds or the execution and delivery by the Issuer of, or the performance of its obligations under, this Bond Purchase Agreement, the

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Bonds, the Resolutions, the Indenture, the Agreement or any other agreement or instrument contemplated hereby or thereby.

(h)There is no action, suit, proceeding, inquiry or investigation, at law or in equity, before or by any court, public board or body, pending against the Issuer or of which the Issuer has otherwise received written official notice or which is, to the knowledge of the Issuer, threatened against the Issuer which in any way questions the validity of the Refunding Act, the powers of the Issuer referred to in paragraph (f) above or the validity of any proceedings taken by the Issuer in connection with the issuance of the Bonds, or wherein an unfavorable decision, ruling or finding would materially adversely affect the transactions contemplated by this Bond Purchase Agreement or which, in any way, would adversely affect the validity or enforceability of this Bond Purchase Agreement, the Bonds, the Resolutions, the Indenture, the Agreement, or any other agreement or instrument to which the Issuer is a party contemplated hereby or thereby.

(i)To the best knowledge of the Issuer, without independent investigation, the adoption of the Resolutions, the authorization, execution and delivery by the Issuer of this Bond Purchase Agreement, the Bonds, the Indenture, the Agreement and any other agreement or instrument to which the Issuer is a party contemplated hereby or thereby and compliance with the provisions of the Resolutions and of each of such instruments will not conflict with or result in a breach of any of the terms or provisions of, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument to which the Issuer is a party or is subject, nor will such action result in any violation of the provisions of any applicable law, including the Refunding Act, or any charter, resolution or regulation of the Issuer, or any existing order, judgment, decree, rule or regulation applicable to the Issuer (or any of its officials or officers in their respective capacities as such) of any court or of any federal, state or other regulatory Issuer or other governmental body having jurisdiction over the Issuer (or such officials or officers as such).

(j)The information in the Official Statement relating to the Issuer does not contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made therein, in light of the circumstances under which they were made, not misleading.

6.Corporation’s Representations. The Corporation makes the following representations as of the date of this Bond Purchase Agreement, all of which will survive the purchase and offering of the Bonds:

(a)The Corporation is a corporation duly incorporated and in good standing under the laws of the State of Delaware and is qualified to do business and is in good standing in each jurisdiction where the ownership of its properties or the conduct of its business requires such qualification, except to the extent that the failure to be so qualified or be in good standing would not have a material adverse effect on the consolidated financial position, stockholders’ equity or results of operations of the Corporation and its subsidiaries, taken as a whole, with full power to execute and deliver the Agreement, the CDU and this Bond Purchase Agreement (collectively, the “Corporation Documents”) and to perform its obligations thereunder and hereunder.

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(b)The Corporation has duly authorized the execution and delivery and performance by the Corporation of the Corporation Documents and all actions necessary and appropriate to carry out its obligations thereunder and hereunder.

(c)This Bond Purchase Agreement has been duly executed and delivered by the Corporation. The Agreement and the CDU, when executed and delivered by the Corporation, will constitute valid and binding obligations of the Corporation, enforceable in accordance with their respective terms, subject to the effects of (i) any applicable bankruptcy, solvency, reorganization, moratorium, fraudulent conveyance or transfer or other laws relating to or affecting creditors’ rights generally, (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and (iii) any implied covenants of good faith and fair dealing.

(d)The execution and delivery of the Corporation Documents and the performance by the Corporation of its obligations hereunder and thereunder will not violate, conflict with or result in a breach of or constitute a default under the Certificate of Incorporation, as amended to the date hereof, of the Corporation or any material indenture, agreement or other instrument by which the Corporation may be bound or any constitutional or statutory provision or order, rule, regulation, decree or ordinance of any court, government or governmental body having jurisdiction over the Corporation, which violation, conflict, breach or default would be reasonably expected to have an adverse effect upon the validity or the issuance of the Bonds or a material adverse effect on the performance by the Corporation of its obligations under the Corporation Documents.

(e)All authorizations, certifications, consents and approvals of, notices to, registrations or filings with, or actions in respect of any governmental body, agency or other instrumentality or court required in connection with the execution, delivery and performance by the Corporation of the Corporation Documents have been obtained, given or taken and are in full force and effect, except where the failure to obtain, give, take or maintain in full force and effect any such authorization, certification, consent, approval, notice, registration or filing would not have an adverse effect on the validity or issuance of the Bonds or a material adverse effect on the performance by the Corporation of its obligations under the Corporation Documents; provided that no representation is made with respect to compliance with the securities or “Blue Sky” laws of any jurisdiction of the United States.

(f)The Corporation has authorized the use of the Official Statement by the Underwriter. The Corporation hereby represents and warrants that the Official Statement is complete as of its date, within the meaning of Rule 15c2-12(f)(3) under the Exchange Act and that the Preliminary Official Statement is “deemed final” as of its date within the meaning of Rule 15c2-12(b)(1) under the Exchange Act, except for permitted omissions in accordance with paragraph (b)(1) thereof.

(g)There is no litigation or proceeding pending or, to the Corporation’s knowledge, threatened against or affecting the Corporation, challenging the validity of the Bonds, the Corporation Documents or seeking to enjoin the performance of the Corporation’s obligations thereunder or hereunder wherein an unfavorable decision, ruling or finding would have an adverse

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effect on the validity or issuance of the Bonds or a material adverse effect on the performance by the Corporation of its obligations under the Corporation Documents.

(h)The Official Statement (including the information included therein by cross-reference) does not contain an untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made therein, in light of the circumstances under which they were made, not misleading; provided that no representation is made as to the statements and information with respect to the book-entry only system or DTC and information contained in the Official Statement under the captions “THE ISSUER,” “UNDERWRITING” and Appendix B; and the financial statements incorporated by reference therein have been prepared in accordance with generally accepted accounting principles in effect in the United States on the respective dates thereof, consistently applied, and fairly present the financial position of the Corporation and its consolidated subsidiaries and the results of their operations at the dates and for the periods indicated. The documents included by cross-reference in the Official Statement complied, as of the respective dates of filing, in all material respects with the applicable requirements of the Exchange Act, and the rules thereunder.

(i)The Corporation will not knowingly take or omit to take any action which action or omission would in any way cause the proceeds from the sale of the Bonds to be applied in a manner contrary to that provided in the Indenture and the Agreement.

(j)Except as disclosed in the Official Statement, the Corporation is in compliance with all of its prior continuing disclosure undertakings entered into pursuant to Rule 15c2-12(b)(5) under the Exchange Act.

7.Issuer’s Covenants. The Issuer will:

(a)Cooperate in qualifying the Bonds for offer and sale under the Blue Sky or other securities laws of states designated by the Underwriter, provided that the Issuer shall not be required to do business or consent to service of process in any state or jurisdiction other than the State or to meet any other requirement deemed by the Issuer to be unduly burdensome provided that provision for the Issuer’s out-of-pocket costs are made.

(b)If, after the date of this Bond Purchase Agreement and until twenty-five (25) days after the end of the underwriting period, as defined in Rule 15c2-12, any event shall occur, or the Issuer shall learn of any fact that might or would cause the Official Statement, as then amended or supplemented, to contain any untrue statement of a material fact or to omit to state a material fact necessary to make the statements made therein, in the light of the circumstances under which they were made, not misleading, or if the Issuer is notified of any such event by the Corporation, the Issuer shall notify the Underwriter thereof, and if in the reasonable opinion of the Underwriter, such event requires an amendment of or a supplement to the Official Statement, the Issuer, with the cooperation and at the expense of the Corporation, shall prepare and furnish to the Underwriter an amendment of or a supplement to the Official Statement so that the Official Statement, as so amended or supplemented, will not contain any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made therein, in the light of the circumstances when the Official Statement is so amended or supplemented, not misleading.

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The Issuer also agrees that it will furnish, before the Official Statement is amended or supplemented, a copy of each proposed amendment or supplement to the Underwriter, who shall have the right to approve such amendment or supplement, which approval shall not be unreasonably withheld.

8.Corporation’s Covenants. The Corporation will:

(a)Agree that any certificate signed by an officer of the Corporation and delivered to the Underwriter shall be deemed a representation and warranty by the Corporation to the Underwriter as to the statements made therein.

(b)Promptly from time to time take such action as the Underwriter may reasonably request to qualify the Bonds for offering and sale under the Blue Sky or other securities laws of such jurisdictions as the Underwriter may request and to comply with such laws so as to permit the continuance of sales and dealings in such jurisdictions for as long as may be necessary to complete the distribution, provided that in connection therewith the Corporation shall not be required to qualify as a foreign corporation or to file a general consent to service of process in any jurisdiction.

(c)If, after the date of this Bond Purchase Agreement and until twenty-five (25) days after the “end of the underwriting period” as defined in Rule 15c2-12, any event shall occur that might or would cause the information contained in the Official Statement to contain any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading, the Corporation shall so notify the Issuer and the Underwriter. If, in the reasonable opinion of the Underwriter or counsel for the Underwriter, such event requires the preparation and publication of an amendment of or a supplement to the Official Statement, the Corporation will cause the Official Statement to be amended or supplemented in form and substance satisfactory to the Underwriter and the Issuer, and all expenses thereby incurred will be paid by the Corporation if such amendment or supplement is prepared and furnished to the Underwriter on or prior to the twenty-fifth day following the Closing. After the twenty-fifth day following the Closing, the Corporation shall not have any liability for expenses incurred in the preparation and publication of an amendment or supplement to the Official Statement, unless such amendment or supplement is necessitated by an event relating to the information contained in the Official Statement relating to the Corporation or any affiliate of any Corporation. For the purposes of this Section 8(c), the Corporation will furnish such information with respect to itself and the refunding of the Prior Bonds as the Underwriter reasonably may from time to time request.

9.Indemnification.

(a)The Company agrees to indemnify and hold harmless the Underwriter and its directors, officers and employees and each person, if any, who controls such Underwriter within the meaning of either Section 15 of the Securities Act of 1933 (the “Securities Act”) or Section 20 of the Exchange Act, from and against any and all losses, claims, damages and liabilities (including, without limitation, any legal or other expenses reasonably incurred by the Underwriter or any such controlling person in connection with defending or investigating any such action or claim) caused by (i) an allegation or determination that the Bonds should have been registered under

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the Securities Act, or that the Indenture should have been qualified under the Trust Indenture Act of 1939, as amended and (ii) any untrue statement or alleged untrue statement of a material fact contained in the Preliminary Official Statement or the Official Statement, or any amendment or supplement thereto, or caused by any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as such losses, claims, damages or liabilities are caused by any such untrue statement or omission or alleged untrue statement or omission based upon information relating to the Underwriter furnished to the Corporation by the Underwriter expressly for use therein under the caption “UNDERWRITING;” provided, however, that the foregoing indemnity agreement with respect to any Preliminary Official Statement shall not inure to the benefit of the Underwriter from whom the person asserting any such losses, claims, damages or liabilities purchased Bonds, or any person controlling the Underwriter, if a copy of the Official Statement (as then amended or supplemented if the Corporation or the Issuer shall have furnished any amendments or supplements thereto) was not sent or given by or on behalf of the Underwriter to such person, if required by law so to have been delivered, at or prior to the written confirmation of the sale of the Bonds to such person, and if the Official Statement (as so amended or supplemented) would have cured the defect giving rise to such losses, claims, damages or liabilities.

The Underwriter agrees to indemnify and hold harmless the Corporation, its directors, its officers who sign the Official Statement and each person, if any, who controls the Corporation within the meaning of either Section 15 of the Securities Act or Section 20 of the Exchange Act to the same extent as the foregoing indemnity from the Corporation to the Underwriter, but only with reference to information relating to the Underwriter furnished to the Corporation by the Underwriter expressly for use in any Preliminary Official Statement, the Official Statement, or any amendments or supplements thereto under the caption “UNDERWRITING.”

In case any proceeding (including any governmental investigation) shall be instituted involving any person in respect of which indemnity may be sought pursuant to either of the two preceding paragraphs, such persons (the “indemnified party”) shall promptly notify the person against whom such indemnity may be sought (the “indemnifying party”) in writing and the indemnifying party, upon request of the indemnified party, shall retain counsel reasonably satisfactory to the indemnified party to represent the indemnified party and any others the indemnifying party may designate in such proceeding and shall pay the fees and disbursements of such counsel related to such proceeding. In any such proceeding, any indemnified party shall have the right to retain its own counsel, but the fees and expenses of such counsel shall be at the expense of such indemnified party unless (i) the indemnifying party and the indemnified party shall have mutually agreed to the retention of such counsel or (ii) the named parties to any such proceeding (including any impleaded parties) include both the indemnifying party and the indemnified party, and the indemnified party reasonably concludes that there may be defenses available to it different from or in addition to those available to the indemnifying party (in which case the indemnifying party will not have the right to assume the defense on behalf of the indemnified party); provided, however, that the indemnifying party shall not, in respect of the legal expenses of any indemnified party in connection with any proceeding or related proceedings in the same jurisdiction, be liable for the fees and expenses of more than one separate firm (in addition to any local counsel) for all such indemnified parties and that all such fees and expenses shall be reimbursed as they are incurred.

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Such firm shall be designated in writing by the Underwriter, in the case of parties indemnified pursuant to the second preceding paragraph, and by the Corporation, in the case of parties indemnified pursuant to the first preceding paragraph. The indemnifying party shall not be liable for any settlement of any proceeding effected without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the indemnifying party agrees to indemnify the indemnified party from and against any loss or liability by reason of such settlement or judgment. Notwithstanding the foregoing sentence, if at any time an indemnified party shall have requested an indemnifying party to reimburse the indemnified party for fees and expenses of counsel as contemplated by the second and third sentences of this paragraph, the indemnifying party agrees that it shall be liable for any settlement of any proceeding effected without its written consent if (a) such settlement is entered into more than 30 days after receipt by such indemnifying party of the aforesaid request and (b) such indemnifying party shall not have reimbursed the indemnified party in accordance with such request prior to the date of such settlement. No indemnifying party shall, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened proceeding in respect of which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party, unless such settlement includes an unconditional release of such indemnified party from all liability on claims that are the subject matter of such proceeding.

To the extent the indemnification provided for in the first paragraph of this subsection is unavailable to an indemnified party or insufficient in respect of any losses, claims, damages or liabilities referred to therein, then each indemnifying party under such paragraph, in lieu of indemnifying such indemnified party thereunder, shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (a) in such proportion as is appropriate to reflect the relative benefits received by the Corporation on the one hand and the Underwriter on the other hand from the offering of the Bonds or (b) if the allocation provided by clause (a) above is not permitted by applicable law, in such portion as is appropriate to reflect not only the relative benefits referred to in clause (a) above but also the relative fault of the Corporation on the one hand and of the Underwriter on the other hand in connection with the statements or omissions that resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations. The relative benefits received by the Corporation on the one hand and the Underwriter on the other hand in connection with the offering of the Bonds shall be deemed to be in the same respective proportions as the net proceeds from the offering of the Bonds (before deducting expenses) received by the Corporation and the total underwriting discounts or commissions received by the Underwriter. The relative fault of the Corporation on the one hand and of the Underwriter on the other hand shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Corporation or by the Underwriter and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

The Corporation and the Underwriter agree that it would not be just and equitable if contribution pursuant to this section were determined by pro rata allocation or by any other method of allocation that does not take account of the equitable considerations referred to in the immediately preceding paragraph. The amount paid or payable by an indemnified party as a result of the losses,

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claims, damages and liabilities referred to in the immediately preceding paragraph shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any, such action or claim.

(b)The Underwriter agrees to indemnify and hold harmless the Issuer, its members, directors and officers, but only with reference to information relating to the Underwriter under the caption “UNDERWRITING” in the Preliminary Official Statement or the Official Statement, or any amendment or supplement thereto.

In case any proceeding (including any governmental investigation) shall be instituted involving any person in respect of which indemnity may be sought pursuant to the preceding paragraph, the Issuer shall promptly notify the Underwriter in writing and the Underwriter upon request of the Issuer, shall retain counsel reasonably satisfactory to the Issuer to represent the Issuer and any others the Underwriter may designate in such proceeding and shall pay the fees and disbursements of such counsel related to such proceeding. In any such proceeding, the Issuer shall have the right to retain its own counsel, but the fees and expenses of such counsel shall be at the expense of the Issuer unless (i) the Underwriter and the Issuer shall have mutually agreed to the retention of such counsel or (ii) the named parties to any such proceeding (including any impleaded parties) include the Underwriter and the Issuer and the Issuer reasonably concludes that there may be defenses available to it different from or in addition to those available to the Underwriter (in which case the Underwriter will not have the right to assume the defense on behalf of the Issuer). It is understood that the Underwriter shall not, in connection with any proceeding or related proceedings in the same jurisdiction, be liable for the fees and expenses of more than one separate firm (in addition to any local counsel) for the Issuer, and that all such fees and expenses shall be reimbursed as they are incurred. Such firm shall be designated in writing by the Issuer. The Underwriter shall not be liable for any settlement of any proceeding effected without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the Underwriter agrees to indemnify the Issuer from and against any loss or liability by reason of such settlement or judgment. Notwithstanding the foregoing sentence, if at any time the Issuer shall have requested the Underwriter to reimburse the Issuer for fees and expenses of counsel as contemplated by the third sentence of this paragraph, the Underwriter agrees that it shall be liable for any settlement of any proceeding effected without its written consent if (i) such settlement is entered into more than 30 days after receipt by the Underwriter of the aforesaid request and (ii) the Underwriter shall not have reimbursed the Issuer in accordance with such request prior to the date of such settlement. The Underwriter shall not, without the prior written consent of the Issuer, effect any settlement of any pending or threatened proceeding in respect of which the Issuer is or could have been a party and indemnity could have been sought hereunder the Issuer, unless such settlement includes an unconditional release of the Issuer from all liability on claims that are the subject matter of such proceeding.

If the indemnification provided for in this subsection (b) is unavailable to the Issuer in respect of any losses, claims, damages or liabilities referred to therein, then the Underwriter, in lieu of indemnifying the Issuer, shall contribute to the amount paid or payable by the Issuer as a result of such losses, claims, damages or liabilities (i) in such proportion as is appropriate to reflect the relative benefits received by the Issuer and the Underwriter from the limited public offering of the Bonds or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in

12

such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Issuer and of the Underwriter in connection with the statements or omissions that resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations. The relative benefits received by the Issuer and the Underwriter shall be determined by reference to, among other things, the fees and other benefits from the offering received by the Issuer and the total underwriting discounts and commissions received by the Underwriter. The relative fault of the Issuer and the Underwriter shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Issuer or by the Underwriter and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

The Issuer and the Underwriter agree that it would not be just and equitable if contribution pursuant to this subsection (b) were determined by pro rata allocation or by any other method of allocation that does not take account of the equitable considerations referred to in the immediately preceding paragraph. The amount paid or payable by the Issuer as a result of the losses, claims, damages and liabilities referred to in the immediately preceding paragraph shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by the Issuer in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this subsection (b), the Underwriter shall not be required to contribute any amount in excess of the amount by which the total price at which the Bonds underwritten by it and distributed to the public were offered to the public exceeds the amount of any damages the Underwriter has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation shall be entitled to contribution from any person who was not guilty of fraudulent misrepresentation.

The indemnity and contribution agreements contained in this subsection (b) and the representations and warranties of the Issuer contained in the Bond Purchase Agreement shall remain operative and in full force and effect regardless of (i) any termination of the Bond Purchase Agreement, (ii) any investigation made by or on behalf of the Underwriter or any person controlling the Underwriter or by or on behalf of the Issuer, its officers or directors or any other person controlling the Issuer and (iii) acceptance of and payment for any of the Bonds.

(c)The Corporation agrees to indemnify and hold harmless the Issuer and any member, officer, employee or agent thereof (including counsel to the Issuer) from and against any and all losses, claims, damages and liabilities caused by (i) an allegation or determination that the Bonds should have been registered under the Securities Act, or that the Indenture should have been qualified under the Trust Indenture Act of 1939, as amended and (ii) any untrue statement or alleged untrue statement of a material fact contained in the Preliminary Official Statement or the Official Statement, or any amendment or supplement thereto, other than under the captions “TAX EXEMPTION” and “UNDERWRITING” or caused by any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as such losses, claims, damages or liabilities are caused by any such untrue statement or omission or alleged untrue statement or omission based upon information relating to the Issuer furnished to the Corporation in writing by the Issuer expressly for use therein under the captions “THE ISSUER” or “LEGAL MATTERS” (insofar as it relates to the Issuer).

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In case any proceeding (including any governmental investigation) shall be instituted involving any person in respect of which indemnity may be sought pursuant to the preceding paragraph, such person (hereinafter called the indemnified party) shall promptly notify the Corporation in writing and the Corporation upon request of the indemnified party, shall retain counsel reasonably satisfactory to the indemnified party to represent the indemnified party and any others the Corporation may designate in such proceeding and shall pay the fees and disbursements of such counsel related to such proceeding. In any such proceeding, any indemnified party shall have the right to retain its own counsel, but the fees and expenses of such counsel shall be at the expense of such indemnified party unless (i) the Corporation and the indemnified party shall have mutually agreed to the retention of such counsel or (ii) the named parties to any such proceeding (including any impleaded parties) include both the Corporation and the indemnified party and the indemnified party reasonably concludes that there may be defenses available to it different from or in addition to those available to the Corporation or other indemnified parties (in which case the Corporation will not have the right to assume the defense on behalf of the indemnified party). The Corporation shall not be liable for any settlement of any proceeding effected without its written consent, but if settled with such consent or if there be a final judgment for the plaintiff, the Corporation agrees to indemnify the indemnified party from and against any loss or liability by reason of such settlement or judgment. Notwithstanding the foregoing sentence, if at any time an indemnified party shall have requested the Corporation to reimburse the indemnified party for fees and expenses of counsel as contemplated by the third sentence of this paragraph, the Corporation agrees that it shall be liable for any settlement of any proceeding effected without its written consent if (i) such settlement is entered into more than 30 days after receipt by the Corporation of the aforesaid request and (ii) the Corporation shall not have reimbursed the indemnified party in accordance with such request prior to the date of such settlement. The Corporation shall not, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened proceeding in respect of which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party, unless such settlement includes an unconditional release of such indemnified party from all liability on claims that are the subject matter of such proceeding.

To the extent the indemnification provided for in the first paragraph of this section is unavailable to an indemnified party in respect of any losses, claims, damages or liabilities referred to therein, then the Corporation, in lieu of indemnifying such indemnified party thereunder, shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (i) in such proportion as is appropriate to reflect the relative benefits received by the Corporation and the Issuer from the offering of the Bonds or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Corporation and of the Issuer in connection with the allegations, determinations, statements or omissions that resulted in such losses, claims, damages or liabilities, as well as any other relevant equitable considerations; provided however, that in no case (other than gross negligence or willful misconduct of the Issuer) shall the Issuer be responsible for any amount in excess of the fees paid by the Corporation to the Issuer in connection with the issuance and the administration of the Bonds.

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The relative benefits received by the Corporation and the Issuer shall be deemed to be in the same respective proportions as the net proceeds from the offering (before deducting expenses) received indirectly by the Corporation (pursuant to the Agreement) and the net proceeds from the offering (before deducting expenses) received by the Issuer, bear to the aggregate limited public offering price of the Bonds. The relative fault of the Corporation and the Issuer shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact relates to information supplied by the Corporation or by the Issuer and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission.

The Corporation and the Issuer agree that it would not be just and equitable if contribution pursuant to this section were determined by pro rata allocation or by any other method of allocation that does not take account of the equitable considerations referred to in the immediately preceding paragraph. The amount paid or payable by an indemnified party as a result of the losses, claims, damages and liabilities referred to in the immediately preceding paragraph shall be deemed to include, subject to the limitations set forth above, any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim.

10.Conditions of Underwriter’s Obligation.

The Underwriter’s obligation to purchase the Bonds is subject to fulfillment of the following conditions at or before Closing:

(a)The Bonds, the Agreement, the CDU, the Indenture and this Bond Purchase Agreement shall have been duly authorized, executed and delivered in the forms heretofore approved by the Underwriter with only such changes as shall be mutually agreed upon by the Issuer, the Corporation and the Underwriter.

(b)At the time of the Closing, the Official Statement shall not have been amended, modified or supplemented prior to the Closing except as may have been agreed to in writing by the Underwriter.

(c)The Issuer’s and the Corporation’s representations hereunder shall be true in all material respects on and as of the date of Closing.

(d)Neither the Issuer nor the Corporation shall have defaulted in the performance of any of its covenants hereunder.

(e)The Underwriter shall have received the following:

(i)an opinion of Bond Counsel, dated the date of Closing, substantially in the form set forth in Appendix B to the Official Statement and an opinion of Bond Counsel, dated the date of Closing and satisfactory to the Underwriter, covering the matters set forth in Exhibit A hereto;

15

(ii)an opinion of Keith E. Green, Jr., Esq., LaPlace, Louisiana, counsel to the Issuer, dated the date of Closing covering the matters set forth in Exhibit B hereto;

(iii)opinions of (x) Reginald Hedgebeth, Senior Vice President, General Counsel and Secretary of the Corporation and (y) Kean Miller LLP, Baton Rouge, Louisiana, special counsel to the Corporation, each dated the date of Closing, covering the matters set forth in Exhibit C hereto;

(iv)an opinion of Ballard Spahr LLP, Philadelphia, Pennsylvania, counsel for the Underwriter, dated the date of Closing, covering the matters set forth in Exhibit D hereto;

(v)certified copies of the Resolutions authorizing the sale and delivery of the Bonds and other related matters; and

(vi)such additional documentation as Bond Counsel or the Underwriter may reasonably request to evidence compliance with applicable law, the validity of the Bonds, the Indenture, and the Corporation Documents.

(f)At Closing there shall have been no material adverse change in the business, properties or financial condition of the Corporation and its consolidated subsidiaries, taken as a whole, from that set forth in or contemplated by the Official Statement which in the judgment of the Underwriter is material and adverse and makes it inadvisable or impractical to proceed with the sale and delivery of the Bonds on the terms contemplated by the Official Statement; and the Underwriter shall have received certificates, dated as of the Closing and signed by an officer or authorized representative of the Corporation (who may rely upon the best of his knowledge based on reasonable investigation) to that effect.

11.Termination of Bond Purchase Agreement.

The Underwriter may terminate its obligation to purchase the Bonds by written notice to the Issuer and the Corporation at any time before Closing if any of the following occurs after the date hereof:

(a)the marketability of any such Bonds or the market price thereof, in the opinion of the Underwriter, has been materially adversely affected by an amendment to the Constitution of the United States or the Constitution of the State or by any legislation (A) enacted by the United States of America, (B) enacted by the State, (C) recommended to the Congress of the United States or otherwise endorsed for passage, by the President of the United States, the Chairman or ranking minority member of the Committee on Finance of the United States Senate or the Committee on Ways and Means of the United States House of Representatives, the Treasury Department of the United States or the Internal Revenue Service, or (D) favorably reported for passage to either House of the Congress of the United States by any Committee of such House to which such legislation has been referred for consideration, or by any decision of any court of the United States of America or any court of the State or by any ruling or regulation (final, temporary or proposed) on behalf of the Treasury Department of the United States, the Internal Revenue Service

16

or any other authority of the United States of America or the State, or any comparable legislative, judicial or administrative development affecting the federal or state tax status of the Issuer, its property or income or the interest on bonds of the Issuer (excluding any bonds, other than the Bonds, issued by the Issuer as a conduit issuer);

(b)trading generally shall have been suspended or materially limited on or by, as the case may be, any of the New York Stock Exchange;

(c)trading of any securities of the Corporation shall have been suspended on any exchange or in any over-the-counter market;

(d)a general moratorium on commercial banking activities in New York shall have been declared by either Federal or New York State authorities;

(e)a material disruption in commercial banking or securities settlement, payment or clearing services in the United States shall have occurred;

(f)there shall have occurred any outbreak or escalation of hostilities or any change in financial markets or any change in political or economic conditions or any calamity or crisis that, in the Underwriter’s judgment, is material and adverse to the offer and sale of the Bonds (other than as specifically listed in the other clauses of this Section 11);

(g)legislation shall have been enacted or recommended to the Congress of the United States or otherwise endorsed for passage by the President of the United States or the Chairman or a ranking minority member of the committees of the United States Senate or the House of Representatives with jurisdiction over securities laws matters, or a decision by a court of the United States of America shall be rendered, or a ruling, regulation, proposed regulation by or on behalf of the SEC or other governmental agency having jurisdiction of the subject matter shall be made, that, in the opinion of counsel to the Underwriter, has the effect of requiring the Bonds or any securities of the Issuer to be registered under the Securities Act or requiring the Indenture to be qualified under the Trust Indenture Act of 1939, as amended; or

(h)a stop order, release, regulation or no-action letter by or on behalf of the SEC or any other governmental agency having jurisdiction of the subject matter shall have been issued or made to the effect that the issuance, offering or sale of the Bonds, including all the underlying obligations as contemplated hereby or by the Official Statement, or any document relating to the issuance, offering or sale of the Bonds is or would be in violation of any provision of the federal securities laws at Closing, including, but not limited to, the Securities Act and the Trust Indenture Act of 1939, as amended.

If the Underwriter terminates its obligation to purchase the Bonds because any of the conditions specified in Section 10 shall not have been fulfilled at or before the Closing or because one of the events specified in this Section 11 has occurred, such termination shall not result in any liability on the part of the Issuer or the Underwriter.

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12.Expenses. All expenses and costs of the Issuer incident to the performance of its obligations in connection with the authorization, issuance and sale of the Bonds to the Underwriter, including any costs of mailing or delivery and of printing of the Bonds, the Indenture, the Corporation Documents, the Preliminary Official Statement and the Official Statement, including any amendments thereof or supplements thereto, and all ancillary papers prepared in connection with the transactions contemplated by this Bond Purchase Agreement, in reasonable quantities, including any photocopying thereof, underwriting fees (which will include reasonable out-of-pocket costs and fees and expenses of counsel to the Underwriter), fees and expenses of Bond Counsel, the Issuer’s fees, fees and expenses of Issuer Counsel, fees and expenses of the Trustee in connection with the issuance of the Bonds and fees charged by investment rating agencies for the rating of the Bonds shall be paid by the Corporation. Whether or not the Bonds are sold hereunder, the Corporation will pay the Underwriter’s out-of-pocket expenses in connection with its offering of the Bonds; provided, however, if the Bonds are not sold because of a default by the Underwriter hereunder, the Corporation will not pay such expenses.

13.Execution in Counterparts. This Bond Purchase Agreement may be executed in several counterparts, each of which shall be regarded as an original and all of which shall constitute but one and the same agreement.

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14.Notices and other Actions. All notices, demands and formal actions hereunder will be in writing and mailed, telexed, telecopied or delivered to:

The Underwriter:

Morgan Stanley & Co. LLC

1585 Broadway, 16^th Floor

New York, New York 10036

Attention: Mr. Francis J. Sweeney

Telecopier: (212) 507-2375

The Corporation:

Marathon Oil Corporation

5555 San Felipe, Suite 1828

Houston, Texas 77056

Attention: Vice President and Treasurer

Telecopier: (713) 499-8413

The Issuer:

Parish of St. John the Baptist, State of Louisiana

1801 W. Airline Highway

LaPlace, Louisiana 70068

Attention: Parish President

Telecopier: (985) 652-1700

15.Governing Law. This Bond Purchase Agreement shall be governed by, and construed in accordance with, the laws of the State of New York, except that the rights, duties and obligations of the Issuer shall be governed by the laws of the State.

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IN WITNESS WHEREOF, the parties have executed and delivered this Bond Purchase Agreement as of the date first above written.

	PARISH OF ST. JOHN THE BAPTIST, STATE OF LOUISIANA
	By: /s/ Natalie Robottom
	Parish President
Attest: By: /s/ Jackie Landeche
Secretary, St. John the Baptist Parish       Council
	MARATHON OIL CORPORATION
	By: /s/ Morris R. Clark
	Name: Morris R. Clark Title: Vice President and Treasurer
	MORGAN STANLEY & CO. LLC
	By: /s/ Francis J. Sweeney
	Name: Francis J. Sweeney Title: Managing Director

Signature Page to Bond Purchase Agreement

DMEAST #32398136

SCHEDULE 1

$1,000,000,000

Parish of St. John the Baptist, State of Louisiana

Revenue Refunding Bonds (Marathon Oil Corporation Project)
Series 2017

Price: 100%

CUSIP No.* 79020FAV8

Last Day of Initial Term Rate Period: June 1, 2037

First Interest Payment Date: June 1, 2018

Interest Payment Dates: Generally, first day of the sixth calendar month following the beginning of the Term Rate Period

Maturity Date: June 1, 2037

Capitalized terms used but not defined in this Schedule 1 shall have the meanings assigned to such terms in the Indenture or the Agreement (each as defined in the Bond Purchase Agreement).

Optional Tender of Bonds

In addition to, and notwithstanding anything to the contrary contained in the Indenture, while there are Bonds that are owned of record or beneficially by the Corporation or any affiliate thereof (the “Corporation Bonds”), the Owner thereof may elect to have its Bonds (or portion thereof in amounts equal to the lowest denomination then authorized by the Indenture or whole multiples of such lowest denomination) purchased at the Purchase Price on any Business Day upon written or electronic notice of tender given to the Trustee and the Remarketing Agent for such Bonds, directly or through the Owner’s DTC Participant, no later than 4:00 p.m., New York City time, on a Business Day not fewer than forty-five days prior to the purchase date. The Corporation shall exercise such option only if it has entered into a Remarketing Agreement in accordance with the Indenture.

Mandatory Tender for Purchase

The Bonds are subject to mandatory tender for purchase at the Purchase Price, as described below, as follows:

Mandatory Tender at the End of Each Term Rate Period. Bonds accruing interest at a Term Rate will be subject to mandatory tender for purchase on the day after the last day of each Term Rate Period applicable to such Bond.

Schedule 1

Mandatory Tender upon a Conversion between Rate Periods for the Bonds. Bonds to be converted from one Rate Period to a different interest Rate Period, are subject to mandatory tender for purchase on the date of conversion.

Optional Redemption

Bonds accruing interest at a Term Rate for a period of ten years or more shall be subject to optional redemption, in whole or in part, and if in part, at the lowest authorized denomination or any whole multiple thereof, at the written direction of the Corporation, at any time on and after the tenth anniversary of the commencement of such Term Rate Period at an optional redemption price equal to 100% of the principal amount thereof, together with accrued interest to the redemption date. Each Bond accruing interest at a Term Rate for a period of less than ten years is not subject to optional redemption.

Special Mandatory Redemption

The Bonds shall be subject to special mandatory redemption prior to maturity on a date selected by the Corporation not later than 180 days after the occurrence of a Determination of Taxability (as defined below) at a redemption price equal to 100% of the principal amount thereof, plus accrued interest to the redemption date. Any such special mandatory redemption shall be in whole unless it is finally determined as evidenced by an opinion of nationally recognized bond counsel addressed to the Issuer and the Trustee or by the applicable Final Determination (as defined below) that less than all of the Bonds may be redeemed without adversely affecting the exclusion of interest on the remaining Bonds from gross income for federal income tax purposes, in which case only such amount need be redeemed. “Determination of Taxability” means a Final Determination by the Internal Revenue Service or by a court of competent jurisdiction in the United States that, or an opinion of nationally recognized bond counsel selected by the Corporation to the effect that, as a result of failure by the Corporation to observe or perform any covenant, condition or agreement on its part to be observed or performed under the Agreement or as a result of the inaccuracy of any representation made by the Corporation under the Agreement, the interest payable on any Bond is or will become includable in the gross income of the owner of such Bond for federal income tax purposes (other than an owner who is a substantial user or related person within the meaning of Section 147(a) of the Internal Revenue Code of 1986, as amended (the “Code”)). “Final Determination” means, with respect to a private letter ruling or a technical advice memorandum or determination of the Internal Revenue Service, written notice thereof in a proceeding in which the Corporation had an opportunity to participate and otherwise means written notice of a determination from which no further right of appeal exists or from which no appeal is timely filed with any court of competent jurisdiction in the United States in a proceeding to which the Corporation was a party or in which the Corporation had the opportunity to participate.

In addition, in the event the Corporation or the Issuer enters into a settlement agreement with the Internal Revenue Service whereby the Corporation agrees to cause the redemption of all or a portion of the Bonds in response to a claim by the Internal Revenue Service that, for the reasons stated in the definition of “Determination of Taxability”, the interest payable on such Bonds is or will become includable in the gross income of the owner of such Bond for federal income tax purposes (other than an owner who is a substantial user or related person within the meaning of

Schedule 1

Section 147(a) of the Code), such Bonds shall be subject to special mandatory redemption on a date selected by the Corporation in accordance with such settlement agreement at a redemption price equal to 100% of the principal amount thereof, plus accrued interest to the redemption date.

If the Trustee receives written notice from any owner of a Bond stating that (a) such party has been notified in writing by the Internal Revenue Service that it proposes to include the interest on any Bond in the gross income of such party for the reasons stated in the definition of “Determination of Taxability” set forth above or any other proceeding has been instituted against such party that may lead to a Final Determination as described in the aforesaid definition, and (b) such party will afford the Corporation the opportunity to contest the same, either directly or in its name, and until a conclusion of any appellate review, if sought, then the Trustee shall promptly give notice thereof to the Corporation, the Issuer and the owners of Bonds then outstanding. If a Final Determination thereafter occurs, the Trustee shall make demand for prepayment of the unpaid debt service payments, or necessary portions thereof, from the Corporation and give notice of the special mandatory redemption of the appropriate amount of Bonds on the date selected by the Corporation within the required period of 180 days.

Extraordinary Optional Redemption

The Bonds are subject to extraordinary optional redemption by the Issuer, at the direction of the Corporation, in whole or in part, at a redemption price of 100% of the principal amount thereof, plus accrued interest to the redemption date on any date within one year after, as a result of any changes in the Constitution of Louisiana or the Constitution of the United States of America or of legislation or administrative action (whether local, state or federal) or by final decree, judgment or order of any court or administrative body (whether local, state or federal) the Agreement shall have become void or unenforceable or impossible to perform in accordance with the intent and purposes of the parties as expressed in the Agreement, or shall have been declared to be unlawful.

Purchase in Lieu of Redemption

When Bonds are subject to optional redemption, the Corporation may elect to purchase such Bonds in lieu of redemption on the applicable redemption date at a purchase price equal to the redemption price, plus accrued interest thereon to but not including the date of such purchase, by delivering to the Trustee a written request to such effect on or before the Business Day prior to the date such Bonds would otherwise be subject to redemption. Moneys received for such purchase shall be held by the Trustee in the Corporation Purchase Account established under the Indenture for the Registered Owners of the Bonds so purchased.

Schedule 1

SCHEDULE 2

None

Schedule 2

EXHIBIT A

Points to be Covered in
Supplemental Opinion of Bond Counsel
(Terms defined in Bond Purchase Agreement
are used here with same meanings)

1.The Bonds are exempt securities under the Securities Act, and, in connection with the offer and sale of the Bonds, no registration of the Bonds under such Act or qualification of the Indenture under the Trust Indenture Act of 1939, as amended, is required. No opinion need be expressed as to the state securities law of any jurisdiction.

2.The Bond Purchase Agreement has been duly authorized, executed and delivered by the Issuer and, assuming due and valid authorization, execution and delivery of the Bond Purchase Agreement by the parties thereto other than the Issuer, constitutes a valid and binding obligation except to the extent that the enforceability thereof may be limited by bankruptcy, reorganization, moratorium, or other similar laws relating to or affecting creditors’ rights generally and to the extent that certain equitable remedies, including specific performance, may be unavailable.

3.All consents, approvals or other actions of governmental bodies required to be obtained by the Issuer for the valid execution and delivery of the Indenture and the Agreement by the Issuer and the valid issuance of the Bonds by the Issuer have been obtained.

4.The summary descriptions in the Official Statement under the captions “INTRODUCTORY STATEMENT,” “THE BONDS” (except under the subsection “Book-Entry-Only System”), “THE AGREEMENT,” and “THE INDENTURE” insofar as such descriptions purport to describe the Issuer or to summarize certain matters of law or provisions of the Bonds, the Indenture and the Agreement fairly and accurately present the information purported to be shown therein.

Such opinion shall also state that nothing has come to counsel’s attention that would lead counsel to believe that the information under the captions “THE ISSUER” or “TAX EXEMPTION” in the Official Statement contains any untrue statement of a material fact or omits to state any material fact necessary to make the statements therein, in light of the circumstances under which they were made, not misleading.

A-1

EXHIBIT B

Points to be Covered in
Opinion of Counsel to the Issuer
(Terms defined in Bond Purchase Agreement
are used here with same meanings)

1.The Issuer is a parish and a political subdivision of the State of Louisiana created and existing pursuant to Louisiana law, including particularly the Constitution of Louisiana. The Issuer has the power to acquire, hold title to and lease or otherwise dispose of the Project and to issue the Bonds under the provisions of Chapter 14-A of Title 39 of the Louisiana Revised Statutes of 1950, as amended.

2.The Resolutions have been duly adopted and the Agreement, the Bond Purchase Agreement, the Bonds and the Indenture have been duly authorized, executed, and delivered by the Issuer and constitute legal and binding obligations of the Issuer enforceable in accordance with their respective terms (except to the extent that the obligations of the Issuer and the enforceability thereof are subject to general principles of equity and to applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws relating to or affecting creditors’ rights generally).

3.The adoption of the Resolutions and the execution and delivery of the Agreement, the Bond Purchase Agreement, and the Indenture, and the issuance of the Bonds, and the performance by the Issuer of its obligations thereunder, to such counsel’s knowledge, do not and will not violate or constitute a default under any judgment, decree, or contract to which it is a party or by which the Issuer or its property is bound and no approval or other action by any governmental authority or agency is required in connection with the securities laws of any jurisdiction, whether federal or state.

4.The statements contained in the Official Statement under the caption “THE ISSUER” are fair and accurate summaries of the matters set forth therein.

5.To the best of such counsel’s knowledge, there is no action, suit, proceeding, or investigation at law or in equity before or by any court or governmental agency or body pending or threatened against or affecting the Issuer, or, to such counsel’s knowledge, any basis therefor, wherein an unfavorable decision, ruling, or finding would adversely affect the organization or existence of the Issuer, the transactions contemplated by the Bond Purchase Agreement, the Indenture, and the Agreement, or which affect the validity or enforceability of the Bonds, the Indenture, or the Agreement.

6.The use of the Official Statement has been duly authorized by the Issuer.

B-1

EXHIBIT C

Points to be Covered in
Opinions of Counsel to the Corporation
(Terms defined in Bond Purchase Agreement
are used here with same meanings)

1.The Corporation is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware, is duly qualified to transact the business in which it is engaged in each jurisdiction in which the failure to so qualify would have, in aggregate, a material adverse effect on the Corporation or its business and has full corporate power and authority to transact the business in which it is engaged and to execute, deliver and perform its obligations under the Corporation Documents.

2.The Agreement and the CDU have each been duly authorized, executed and delivered by the Corporation and constitute the legal, valid and binding obligations of the Corporation enforceable against it in accordance with their respective terms except as affected by bankruptcy, insolvency, moratorium or other laws generally affecting the enforcement of creditors’ rights and general principles of equity and except as rights to indemnity may be limited under federal or state securities laws.

3.The execution and delivery of the Corporation Documents by the Corporation and the performance by the Corporation of its obligations thereunder do not and will not violate or constitute a default under the Certificate of Incorporation of the Corporation or, to such counsel’s knowledge, any (i) order, writ, judgment or decree to which the Corporation is a party or is subject, or (ii) agreement, indenture, mortgage, lease or instrument to which the Corporation is a party or is subject that is material to the Corporation and its subsidiaries, taken as a whole.

4.To the best of counsel’s knowledge there is no action, suit, proceeding, inquiry or investigation at law or in equity before or by any judicial or administrative court or agency, state or federal or other, pending or threatened against or affecting the Corporation which would affect the validity of the Corporation Documents or materially affect the performance by the Corporation of its obligations under the Corporation Documents or the transactions contemplated thereby or have a material adverse effect on the current or future consolidated financial position, stockholder’s equity or results of operations of the Corporation and its subsidiaries.

5.No additional or further approval, consent or authorization of any federal, state or local governmental or public agency or authority (other than state Blue Sky or securities authorities), not already obtained, is required to be obtained by the Corporation in connection with entering into the Corporation Documents or the performance of its obligations thereunder.

6.The descriptions and summaries of the Bonds, the Agreement and the Indenture in the Preliminary Official Statement and the Official Statement are accurate in all material respects and fairly present the information intended to be shown with respect thereto.

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7.The documents included by cross-reference in the Preliminary Official Statement and the Official Statement (other than the financial statements therein, as to which counsel need express no opinion), when they were filed with the SEC or to the extent such documents were subsequently amended prior to the date hereof, at the time so amended,, complied as to form in all material respects with the requirements of the Exchange Act and the rules and regulations of the SEC thereunder.

8.In reliance upon the opinion of Foley & Judell, L.L.P., Bond Counsel, that interest on the Bonds is excludable from gross income for federal income tax purposes under existing law, no registration with the SEC under the Securities Act need to be made in connection with the offering and sale of the Bonds and no indenture is required to be qualified under the Trust Indenture Act of 1939, as amended.

Such opinion shall also state that nothing has come to counsel’s attention that would lead counsel to believe that the Preliminary Official Statement or the Official Statement (other than the financial statements included or incorporated by cross-reference therein, any statements and information with respect to the book-entry only system or DTC and the information contained therein under the captions the “THE ISSUER,” “TAX EXEMPTION” or “UNDERWRITING,” as to which counsel need express no opinion) contains any untrue statement of a material fact or omits to state any material fact necessary to make the statements therein, in light of the circumstances under which they were made, not misleading.

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EXHIBIT D

Points to be Covered in Opinion
of Counsel for the Underwriter
(Terms defined in Bond Purchase Agreement
are used herein with the same meanings)

1.The conditions in the Bond Purchase Agreement to your obligation to purchase the Bonds have been satisfied.

2.No registration need be made with the Securities and Exchange Commission under the Securities Act of 1933, as amended, in connection with the offering and sale of the Bonds, and neither the Indenture nor any other instrument is required to be qualified under the Trust Indenture Act of 1939, as amended, in connection with the offering and sale of the Bonds.

3.The CDU complies with the requirements of paragraph (b)(5) of Rule 15c2-12 promulgated pursuant to the Securities Exchange Act of 1934, as amended, in effect as of the date hereof.

4.    With reliance on an opinion of Counsel to the Corporation as to due authorization, execution and delivery, the Bond Purchase Agreement constitutes the legal, valid and binding obligation of the Corporation enforceable against it in accordance with its terms.

We are not passing upon and do not assume any responsibility for the accuracy, completeness or fairness of any of the statements in the Preliminary Official Statement and the Official Statement and make no representation that we have independently verified the accuracy, completeness or fairness of any such statements. However, to assist you in your investigation concerning the Preliminary Official Statement and the Official Statement, certain of our lawyers responsible for this matter have reviewed certain documents and have participated in conferences in which the contents of the Preliminary Official Statement and the Official Statement and related matters were discussed. During the course of our work on this matter, nothing has come to our attention that leads us to believe that the Preliminary Official Statement, as of its date, and the Official Statement, as of its date or as of this date, contained or contains any untrue statement of a material fact or omitted (other than, with respect to the Preliminary Official Statement, the omission of information permitted to be omitted by Rule 15c2-12 promulgated pursuant to the Securities Exchange Act of 1934, as amended, in effect on the date hereof) or omits to state any material fact necessary in order to make the statements made in the Preliminary Official Statement and the Official Statement, in light of the circumstances under which they were made, not misleading; provided, however, we express no opinion as to (a) expressions of opinion, assumptions, projections, financial statements, or other financial, numerical, economic, demographic, statistical or accounting data, or information or assessments of or reports on the effectiveness of internal control over financing reporting contained in the Preliminary Official Statement and the Official Statement or in any Appendices thereto, (b) any information or statements relating to the book-entry-only system and The Depository Trust Company and (c) Appendix B (Proposed Form of Opinion of Bond Counsel) of the Preliminary Official Statement and the Official Statement.

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EXHIBIT E

Form of Issue Price Certificate

This certificate is furnished by Morgan Stanley & Co. LLC (the “Underwriter”), in connection with the purchase of $1,000,000,000 aggregate principal amount of Revenue Refunding Bonds (Marathon Oil Corporation Project) Series 2017 (the “Bonds”), of the Parish of St. John the Baptist, State of Louisiana (the “Issuer”), at a negotiated sale. The undersigned hereby certifies as set forth below with respect to the sale and issuance of the Bonds:

1.    The undersigned is duly authorized to execute this certificate on behalf of the Underwriter and has been fully apprised of the facts and circumstances forming the basis of this certificate.

2.    As of the date of this certificate, for the only Maturity of the Bonds, the first price at which at least 10% of such Maturity was sold to the Public is the respective price listed in Schedule A.

3.    The Underwriter has (a) determined the aggregate purchase price of the Bonds to be $1,000,000,000, representing the aggregate principal amount of the Bonds, (b) determined the yield on the Bonds for arbitrage purposes, calculated in accordance with the methodology set forth in the Code, to be ______%; and (c) determined the weighted average maturity of the Bonds, calculated based on reoffering price, to be _______ years.

4.    No Bonds were sold in exchange for property or rights to use any other types of property.

5.    In addition to terms defined elsewhere herein, the terms below shall have the following meanings in this certificate:

(a) “Maturity” means Bonds with the same credit and payment terms. Bonds with different maturity dates, or Bonds with the same maturity date but different stated interest rates, are treated as separate maturities.

(b) “Public” means any person (including an individual, trust, estate, partnership, association, company, or corporation) other than an Underwriter or a related party to an Underwriter and, for these purposes, including Marathon Oil Corporation. The term “related party” for purposes of this certificate generally means any two or more persons who have greater than 50 percent common ownership, directly or indirectly.

(c) “Sale Date” means the first day on which there is a binding contract in writing for the sale of a Maturity of the Bonds. The Sale Date of the Bonds is November 28,  2017.

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(d) “Tax Compliance Certificate” means the No-Arbitrage Certificate for the Bonds to which this certificate is attached.

(e) “Underwriter” means, collectively, (i) any person that agrees pursuant to a written contract with the Issuer (or with the lead underwriter to form an underwriting syndicate) to participate in the initial sale of the Bonds to the Public, and (ii) any person that agrees pursuant to a written contract directly or indirectly with a person described in clause (i) of this paragraph to participate in the initial sale of the Bonds to the Public (including a member of a selling group or a party to a retail distribution agreement participating in the initial sale of the Bonds to the Public).

The representations set forth in this certificate are limited to factual matters only. We are not engaged in the practice of law, and nothing in this certificate represents our interpretation of any laws, including specifically Sections 103 and 148 of the Internal Revenue Code of 1986, as amended, and the Treasury Regulations thereunder. The undersigned understands that the foregoing information will be relied upon by the Issuer with respect to certain of the representations set forth in the Tax Compliance Certificate and with respect to compliance with the federal income tax rules affecting the Bonds, and by Foley & Judell, L.L.P., as bond counsel, in connection with rendering its opinion that the interest on the Bonds is excluded from gross income for federal income tax purposes, the preparation of the Internal Revenue Service Form 8038, and other federal income tax advice that it may give to the Issuer from time to time relating to the Bonds; however, the foregoing information may not be relied upon by any other person for any other purpose.

MORGAN STANLEY & CO. LLC

By:     __________________________________________

Name:    

Title:    

Date: ________, 2017.

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SCHEDULE A

SALE PRICE OF THE BONDS

(Attached)

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EX-10.12

Exhibit 10.12

MARATHON OIL CORPORATION

2016 INCENTIVE COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

2017 - 2019 PERFORMANCE CYCLE

Section 16 Officer

1.Grant of Performance Units. Pursuant to this Award Agreement and the Marathon Oil Corporation 2016 Incentive Compensation Plan (the “Plan”), MARATHON OIL CORPORATION (the “Corporation”) hereby grants to [NAME] (the “Participant”), an employee of the Corporation or a Subsidiary, on February 22, 2017, [NUMBER] Performance Units, subject to the terms and conditions set forth in this Award Agreement and the Plan. The Participant has no legally binding right to any payment prior to the vesting of the Performance Units in accordance with the terms of this Award Agreement.

2.Relationship to the Plan and Definitions.

(a) This grant of Performance Units is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, that have been adopted by the Committee. Except as defined in this Award Agreement, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan.

(b) For purposes of this Award Agreement:

“Change in Control,” unless otherwise defined by the Committee, means a change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended, whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i) any person (as defined in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation's then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities,

or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of

the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below);

(ii)the following individuals cease for any reason to constitute a majority of the number of Directors then serving: individuals who, on the date hereof, constitute the Board and any new Director (other than a Director whose initial assumption of office is in connection with an actual or threatened election contest including but not limited to a consent solicitation, relating to the election of Directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation's stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were Directors on the date hereof or whose appointment, election or nomination for election was previously so approved; or

(iii)there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation's assets.

Notwithstanding any other provision to the contrary, in no event shall the transfer of ownership interests in the Corporation in and of itself constitute a Change in Control under this Award Agreement.

“Employment” means employment with the Corporation or any of its Subsidiaries. For purposes of this Award Agreement, Employment shall also include any period of time during which the Participant is on Disability status.

“End Stock Price” means the average of the daily closing price of a share of Common Stock for each trading day of December 2019, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period. Notwithstanding the foregoing, if a Change in Control occurs before December 31, 2018, End Stock Price shall mean the closing price of a share of Common Stock on the last regular trading date immediately preceding the effective date of such Change in Control.

“Forfeiture Event” means the occurrence of at least one of the following (a) the Corporation is required, pursuant to a determination made by the Securities and Exchange Commission or by the Audit and Finance Committee of the Board, to prepare a material accounting restatement due to the noncompliance of the Corporation with any financial reporting requirement under applicable securities laws as a result of misconduct, and the Committee determines that (1) the Participant knowingly engaged in the misconduct, (2) the Participant was grossly negligent with respect to such misconduct or (3) the Participant knowingly or grossly negligently failed to prevent the misconduct or (b) the Committee concludes that the Participant engaged in fraud, embezzlement or other similar misconduct materially detrimental to the Corporation.

“Payout Value” means, except as provided in Paragraphs 6 or Paragraph 8 of this Award Agreement, for each Performance Unit the Fair Market Value of a share of Common Stock on December 31, 2019.

“Peer Group” means the following group of eleven companies (in addition to the Corporation): Anadarko Petroleum Corp., Apache Corp., Chesapeake Energy Corp., Continental Resources, Devon Energy Corp., Encana Corp., EOG Resources Inc., Hess Corp., Murphy Oil Corp., Noble Energy Inc., and Pioneer Natural Resources. If, at the end of the Performance Cycle, one or more than one of the corporations in the Peer Group either ceases to exist or is no longer a company for which TSR can be calculated from publicly available information, then one or more of Concho Resources Inc., Newfield Exploration Company and Cimarex Energy shall be substituted as members of the Peer Group, in the order in which they are here listed, to ensure that the Peer Group consists of eleven companies (in addition to the Corporation).

“Performance Cycle” means the period from January 1, 2017 to December 31, 2019. Notwithstanding the foregoing, if a Change in Control occurs before December 31, 2019, then the Performance Cycle shall be the period from January 1, 2017 to the last regular trading date immediately preceding the effective date of such Change in Control.

“Performance Unit” means an unfunded and unsecured right to receive a cash payment determined in accordance with the terms of this Award Agreement and the Plan.

“Retirement” means (i) for an Employee participating in the Retirement Plan, termination on or after the time at which the Employee is eligible for retirement under the Retirement Plan, or (ii) for an Employee not participating in the Retirement Plan, (a) for an Employee with ten or more years of Employment, termination on or after the Employee's 50th birthday or (b) termination on or after the Employee's 65th birthday.

“Retirement Plan” means the Retirement Plan of Marathon Oil Company, or a successor plan to such plan, as applicable.

“Total Shareholder Return” or “TSR” means the rate of return achieved with respect to the company’s common stock as if: (i) $100 were invested in the company’s stock, assuming a purchase price

equal to the average closing price for the calendar month immediately before the start of the performance period, (ii) all dividends paid during the performance period were reinvested into additional shares, and (iii) assuming the company’s stock is valued at the end of the performance period based on the average closing price during the final month of the performance period.

“TSR Percentile Ranking” means the relative ranking of the Corporation's Total Shareholder Return for the Performance Cycle as compared to the Total Shareholder Return of the Peer Group companies during the Performance Cycle, expressed as a percentile ranking.

“Vesting Percentage” means the percentage (between 0% and 200%) determined by the Committee in accordance with the procedures set forth in Paragraph 3, which shall be used to determine the value of each Performance Unit.

3.Determination of Number of Performance Units Eligible for Vesting.

(a) The Committee shall determine the number of Performance Units eligible for vesting by multiplying (i) the number of Performance Units granted under Paragraph 1 of this Award Agreement and (ii) the Vesting Percentage.

(b)Except as provided in Paragraph 6 of this Award Agreement, the Vesting Percentage will depend upon the Corporation's TSR Percentile Ranking. At its first regularly scheduled meeting following the close of the Performance Cycle, the Committee shall determine the TSR Percentile Ranking and the Vesting Percentage as follows based on the TSR of the Corporation relative to the TSR of the other corporations in the Peer Group:

TSR Ranking of	TSR Percentile	Vesting
Corporation	Ranking	Percentage
1st	100%	200%
2nd	90.9%	182%
3rd	81.8%	164%
4th	72.7%	145%
5th	63.6%	127%
6th	54.5%	109%
7th	45.4%	91%
8th	36.3%	73%
9th	27.2%	54%
10th	18.1%	0%
11th	9%	0%
12th	0%	0%

(c)Notwithstanding anything herein to the contrary, if the TSR calculated for the Performance Cycle is negative, then the Vesting Percentage shall not exceed 100%.

(d)The Committee has sole and absolute authority and discretion to reduce the Vesting Percentage, including to zero, as it may deem appropriate; provided, however, that if the Performance Units vest pursuant to Paragraph 8, the Committee shall not reduce the Vesting Percentage as calculated pursuant to Paragraph 3(b) and 3(c).

4.Vesting of Performance Units. Unless the Participant's right to the Performance Units is previously forfeited or vested in accordance with Paragraphs 5, 6, or 8 or is vested in accordance with Paragraph 7, the Committee shall certify in writing on the date of its first regularly scheduled meeting following the end of the Performance Period whether and to what extent the performance goal described in Paragraph 3 has been achieved and shall determine the Vesting Percentage and number of Performance Units that vest. Following the Committee's certification, the Participant shall vest in and be entitled to receive a cash payment equal to the product of (a) the number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's certification and, in any event, on or before March 15, 2019. If, in accordance with the Committee's determination under Paragraph 3, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

5. Termination of Employment Other than due to Retirement. If Participant's Employment is terminated prior to the close of the Performance Cycle for any reason other than death or Retirement, the Participant's right to the Performance Units shall be forfeited in its entirety as of such termination, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

6. Vesting Upon Termination of Employment due to Death. If Participant's Employment is terminated by reason of death prior to the close of the Performance Cycle, the Participant's right to receive the Performance Units shall vest in full as of the date of death, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market of a share of Common Stock on the date of the Participant's death. A cash payment equal to the vested value of the Performance Units shall be made to the Participant's estate on the first day of the third month following the death of the Participant. Such vesting and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9) shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

7.Vesting Upon Termination of Employment due to Retirement. In the event of the Retirement of the Participant on or after completion of half of the Performance Cycle, the Participant may vest, at the discretion of the Committee, in a number of Performance Units equal to or less than the product of (a) the percentage equal to the days of Participant's Employment during the Performance Cycle divided

by the total days in the Performance Cycle, (b) the number of Performance Units granted under this Award Agreement, and (c) the Vesting Percentage, as determined by the Committee under Paragraph 3. In determining the number of Performance Units that shall vest under this Paragraph 7, the Committee shall consider the contributions of the Participant to the Corporation during the Performance Period, including the Participant’s assistance with transition of his or her responsibilities prior to Retirement and whether the Participant provided appropriate notice or his or her intent to retire. In general, the Committee shall consider notice of at least six months to be appropriate, although longer or shorter periods of notice may be acceptable in light of business conditions and the Participant’s individual circumstances. Notwithstanding anything herein to the contrary, in the event the Committee determines that the Participant has accepted or intends to accept employment with a competitor of any business unit of the Corporation, the Vesting Percentage shall be zero. Following the Committee's determination under this Paragraph 7, the Participant shall be entitled to receive a cash payment equal to the product of (x) the number of vested Performance Units, multiplied by (y) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's vesting determination under this Paragraph 7 and, in any event, on or before March 15, 2020. If, in accordance with the Committee's determination, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full. In the event of the Retirement of the Participant before completion of half of the Performance Cycle, the Participant's right to the Performance Units shall be forfeited in its entirety as of the date of his or her termination of employment, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

8.Vesting Upon a Change of Control. Notwithstanding anything herein to the contrary, upon the occurrence of a Change in Control prior to the end of the Performance Cycle, the Participant's right to receive the Performance Units, unless previously forfeited pursuant to Paragraph 5 or Paragraph 7 or vested pursuant to Paragraph 6, shall vest in full. The Vesting Percentage shall be calculated as provided under Paragraph 3, and the Payout Value for each Performance Unit shall be the applicable End Stock Price. A cash payment equal to the vested value of the Performance Units shall be made on the first day of the third month following the Change in Control; provided, however that if such Change in Control fails to qualify as a “change in control event” within the meaning of Treas. Regs. section 1.409A-3(i)(5), then the cash payment will be made during the first week of January 2020. Such vesting and the making of the related cash payment shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

9.Dividend Equivalents. With respect to each of the Performance Units granted under Paragraph 1, the Participant shall be credited with Dividend Equivalents equal to the amount per share of Common Stock of any ordinary cash dividends declared by the Board with record dates during the period beginning on the first day of the Performance Cycle and ending on the earliest to occur of: (a) the last day of the Performance Cycle, (b) the effective date of a Change in Control and (c) the date on which the Performance Units otherwise vest or are forfeited in accordance with Paragraphs 5, 6, 7 or 8. The Corporation shall pay in cash to the Participant an amount equal to (x) the sum of the aggregate amounts of such Dividend Equivalents credited to the Participant, if any, multiplied by (y) the Vesting Percentage that is applicable to

the related Performance Units, with such amount to be paid as and when any cash payment with respect to the related Performance Units is paid. Any Dividend Equivalents shall be forfeited as and when the related Performance Units are forfeited in accordance with the terms of the Award Agreement.

10.Repayment or Forfeiture Resulting from Forfeiture Event.

(a) If there is a Forfeiture Event either while the Participant is employed or within two years after termination of the Participant's Employment, then the Committee may, but is not obligated to, cause some or all of the Participant's outstanding Performance Units to be forfeited by the Participant.

(b) If there is a Forfeiture Event either while the Participant is employed or within two years after termination of the Participant's Employment and a payment has previously been made in settlement of Performance Units granted under this Award Agreement, the Committee may, but is not obligated to, require that the Participant pay to the Corporation an amount (the “Forfeiture Amount”) up to (but not in excess of) the amount paid in settlement of the Performance Units.

(c) This Paragraph 10 shall apply notwithstanding any provision of this Award Agreement to the contrary and is meant to provide the Corporation with rights in addition to any other remedy which may exist in law or in equity. This Paragraph 10 shall not apply to the Participant following the effective time of a Change in Control.

11.Taxes. In all cases the Participant will be responsible to pay all required withholding taxes associated with the Performance Units.Pursuant to Section 10 of the Plan, the Corporation or its designated representative (which may be a Subsidiary) shall have the right to withhold applicable taxes from the cash otherwise payable to the Participant, or from other compensation payable to the Participant, at the time of the vesting and delivery of such cash payment or to take such other action as may be necessary in the opinion of the Corporation to satisfy all obligations for withholding.

12.No Stockholder Rights. The Participant shall in no way be entitled to any of the rights of a stockholder of the Corporation as a result of this Award Agreement. Specifically, the Performance Units do not have voting rights.

13.Nonassignability. Upon the Participant's death, the Performance Units shall be paid out as provided in Paragraph 6 of this Award Agreement. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Performance Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Performance Units shall have no effect.

14.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Corporation or any

Subsidiary or successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

15.Modification of Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Corporation, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant under this Award Agreement. Without the consent of the Participant, this Award Agreement may be amended or supplemented (i) to cure any ambiguity or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to add to the covenants and agreements of the Corporation for the benefit of the Participant or to add to the rights of the Participant or to surrender any right or power reserved to or conferred upon the Corporation in this Award Agreement; provided, in each case, that such changes or corrections shall not adversely affect the rights of the Participant under this Award Agreement without the Participant’s consent, or (iii) to make such other changes as the Corporation, upon advice of counsel, determines are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or governmental rule or regulation, including any applicable federal or state securities or tax laws.

16. Data Privacy. By accepting the Performance Units subject to the terms of this Award Agreement, the Participant hereby explicitly and unambiguously consents to the collection, use and transfer, in electronic or other form, of the Participant’s personal data, including but not limited to items of data described in this Paragraph 16, by and among Marathon Oil Corporation and its Subsidiaries and affiliates, including the Participant’s employer, (collectively referred to as “Marathon Oil” in this Paragraph 16) for the exclusive purpose of implementing, administering and managing the Participant’s participation in the Plan. The Participant understands and acknowledges that Marathon Oil holds certain personal data about the Participant, including, but not limited to, the Participant’s name, home address and telephone number, date of birth, social insurance number or other identification number, salary, nationality, job title, any shares of stock or directorships held in Marathon Oil, details of all grants or any other entitlement to salary and other cash payments, and shares of stock or units awarded, canceled, forfeited, exercised, vested, unvested or outstanding in the Participant’s favor, for the purpose of implementing, administering and managing the Plan (which information is collectively referred to as “Data” for purposes of this Paragraph 16). The Participant understands and agrees that Data may be transferred to one or more third parties assisting Marathon Oil in the implementation, administration and management of the Plan, that these recipients may be located in the Participant’s country of citizenship, country of residence or elsewhere, and that the recipient’s country may have different data privacy laws and protections than the Participant’s country of citizenship or country of residence. The Participant understands that he or she may request a list with the names and addresses of any recipients of the Data by contacting his or her local human resources representative. The Participant, by acceptance of the Performance Units subject to the terms of this Award Agreement, authorizes the recipients to receive, possess, use, retain and transfer the Data, in electronic or other form, for the purposes of implementing, administering and managing the Participant’s participation in the Plan, including any requisite transfer of such Data as may be required to a broker or other third party with whom the Participant may elect to deposit shares or cash following the lapse of applicable restrictions, and reporting to applicable

tax and other legal authorities. The Participant understands that he or she may, at any time, view the Data, request additional information about the storage and processing of the Data, require any necessary amendments to the Data to correct inaccuracy, or refuse or withdraw the consent provided herein, without cost, by contacting the Participant's local human resources representative in writing. The Participant understands that refusing or withdrawing the Participant’s consent may affect the Participant’s ability to participate in the Plan, and the Participant may obtain additional information about the consequences of refusing to consent or withdrawing consent by contacting his or her local human resources representative.

Marathon Oil Corporation

By:

Authorized Officer

EX-10.13

Exhibit 10.13

MARATHON OIL CORPORATION

2016 INCENTIVE COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

2017 - 2019 PERFORMANCE CYCLE

Officer

1.Grant of Performance Units. Pursuant to this Award Agreement and the Marathon Oil Corporation 2016 Incentive Compensation Plan (the “Plan”), MARATHON OIL CORPORATION (the “Corporation”) hereby grants to [NAME] (the “Participant”), an employee of the Corporation or a Subsidiary, on February 22, 2017, [NUMBER] Performance Units, subject to the terms and conditions set forth in this Award Agreement and the Plan. The Participant has no legally binding right to any payment prior to the vesting of the Performance Units in accordance with the terms of this Award Agreement.

2.Relationship to the Plan and Definitions.

(a) This grant of Performance Units is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, that have been adopted by the Committee. Except as defined in this Award Agreement, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan.

(b) For purposes of this Award Agreement:

“Change in Control,” unless otherwise defined by the Committee, means a change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended, whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i) any person (as defined in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation's then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities,

or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below);

(ii)the following individuals cease for any reason to constitute a majority of the number of Directors then serving: individuals who, on the date hereof, constitute the Board and any new Director (other than a Director whose initial assumption of office is in connection with an actual or threatened election contest including but not limited to a consent solicitation, relating to the election of Directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation's stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were Directors on the date hereof or whose appointment, election or nomination for election was previously so approved; or

(iii)there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation's assets.

Notwithstanding any other provision to the contrary, in no event shall the transfer of ownership interests in the Corporation in and of itself constitute a Change in Control under this Award Agreement.

“Employment” means employment with the Corporation or any of its Subsidiaries. For purposes of this Award Agreement, Employment shall also include any period of time during which the Participant is on Disability status.

“End Stock Price” means the average of the daily closing price of a share of Common Stock for each trading day of December 2019, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period. Notwithstanding the foregoing, if a Change in Control occurs before December 31, 2018, End Stock Price shall mean the closing price of a share of Common Stock on the last regular trading date immediately preceding the effective date of such Change in Control.

“Payout Value” means, except as provided in Paragraphs 6 or Paragraph 8 of this Award Agreement, for each Performance Unit the Fair Market Value of a share of Common Stock on December 31, 2019.

“Peer Group” means the following group of eleven companies (in addition to the Corporation): Anadarko Petroleum Corp., Apache Corp., Chesapeake Energy Corp., Continental Resources, Devon Energy Corp., Encana Corp., EOG Resources Inc., Hess Corp., Murphy Oil Corp., Noble Energy Inc., and Pioneer Natural Resources. If, at the end of the Performance Cycle, one or more than one of the corporations in the Peer Group either ceases to exist or is no longer a company for which TSR can be calculated from publicly available information, then one or more of Concho Resources Inc., Newfield Exploration Company and Cimarex Energy shall be substituted as members of the Peer Group, in the order in which they are here listed, to ensure that the Peer Group consists of eleven companies (in addition to the Corporation).

“Performance Cycle” means the period from January 1, 2017 to December 31, 2019. Notwithstanding the foregoing, if a Change in Control occurs before December 31, 2019, then the Performance Cycle shall be the period from January 1, 2017 to the last regular trading date immediately preceding the effective date of such Change in Control.

“Performance Unit” means an unfunded and unsecured right to receive a cash payment determined in accordance with the terms of this Award Agreement and the Plan.

“Retirement” means (i) for an Employee participating in the Retirement Plan, termination on or after the time at which the Employee is eligible for retirement under the Retirement Plan, or (ii) for an Employee not participating in the Retirement Plan, (a) for an Employee with ten or more years of Employment, termination on or after the Employee's 50th birthday or (b) termination on or after the Employee's 65th birthday.

“Retirement Plan” means the Retirement Plan of Marathon Oil Company, or a successor plan to such plan, as applicable.

“Total Shareholder Return” or “TSR” means the rate of return achieved with respect to the company’s common stock as if: (i) $100 were invested in the company’s stock, assuming a purchase price equal to the average closing price for the calendar month immediately before the start of the performance period, (ii) all dividends paid during the performance period were reinvested into additional shares, and (iii) assuming the company’s stock is valued at the end of the performance period based on the average closing price during the final month of the performance period.

“TSR Percentile Ranking” means the relative ranking of the Corporation's Total Shareholder Return for the Performance Cycle as compared to the Total Shareholder Return of the Peer Group companies during the Performance Cycle, expressed as a percentile ranking.

“Vesting Percentage” means the percentage (between 0% and 200%) determined by the Committee in accordance with the procedures set forth in Paragraph 3, which shall be used to determine the value of each Performance Unit.

3.Determination of Number of Performance Units Eligible for Vesting.

(a) The Committee shall determine the number of Performance Units eligible for vesting by multiplying (i) the number of Performance Units granted under Paragraph 1 of this Award Agreement and (ii) the Vesting Percentage.

(b)Except as provided in Paragraph 6 of this Award Agreement, the Vesting Percentage will depend upon the Corporation's TSR Percentile Ranking. At its first regularly scheduled meeting following the close of the Performance Cycle, the Committee shall determine the TSR Percentile Ranking and the Vesting Percentage as follows based on the TSR of the Corporation relative to the TSR of the other corporations in the Peer Group:

TSR Ranking of	TSR Percentile	Vesting
Corporation	Ranking	Percentage
1st	100%	200%
2nd	90.9%	182%
3rd	81.8%	164%
4th	72.7%	145%
5th	63.6%	127%
6th	54.5%	109%
7th	45.4%	91%
8th	36.3%	73%
9th	27.2%	54%
10th	18.1%	0%
11th	9%	0%
12th	0%	0%

(c)Notwithstanding anything herein to the contrary, if the TSR calculated for the Performance Cycle is negative, then the Vesting Percentage shall not exceed 100%.

(d)The Committee has sole and absolute authority and discretion to reduce the Vesting Percentage, including to zero, as it may deem appropriate; provided, however, that if the Performance Units vest pursuant to Paragraph 8, the Committee shall not reduce the Vesting Percentage as calculated pursuant to Paragraph 3(b) and 3(c).

4.Vesting of Performance Units. Unless the Participant's right to the Performance Units is previously forfeited or vested in accordance with Paragraphs 5, 6, or 8 or is vested in accordance with

Paragraph 7, the Committee shall certify in writing on the date of its first regularly scheduled meeting following the end of the Performance Period whether and to what extent the performance goal described in Paragraph 3 has been achieved and shall determine the Vesting Percentage and number of Performance Units that vest. Following the Committee's certification, the Participant shall vest in and be entitled to receive a cash payment equal to the product of (a) the number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's certification and, in any event, on or before March 15, 2019. If, in accordance with the Committee's determination under Paragraph 3, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

5. Termination of Employment Other than due to Retirement. If Participant's Employment is terminated prior to the close of the Performance Cycle for any reason other than death or Retirement, the Participant's right to the Performance Units shall be forfeited in its entirety as of such termination, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

6. Vesting Upon Termination of Employment due to Death. If Participant's Employment is terminated by reason of death prior to the close of the Performance Cycle, the Participant's right to receive the Performance Units shall vest in full as of the date of death, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market of a share of Common Stock on the date of the Participant's death. A cash payment equal to the vested value of the Performance Units shall be made to the Participant's estate on the first day of the third month following the death of the Participant. Such vesting and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9) shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

7.Vesting Upon Termination of Employment due to Retirement. In the event of the Retirement of the Participant on or after completion of half of the Performance Cycle, the Participant may vest, at the discretion of the Committee, in a number of Performance Units equal to or less than the product of (a) the percentage equal to the days of Participant's Employment during the Performance Cycle divided by the total days in the Performance Cycle, (b) the number of Performance Units granted under this Award Agreement, and (c) the Vesting Percentage, as determined by the Committee under Paragraph 3. In determining the number of Performance Units that shall vest under this Paragraph 7, the Committee shall consider the contributions of the Participant to the Corporation during the Performance Period, including the Participant’s assistance with transition of his or her responsibilities prior to Retirement and whether the Participant provided appropriate notice or his or her intent to retire. In general, the Committee shall consider notice of at least six months to be appropriate, although longer or shorter periods of notice may be acceptable in light of business conditions and the Participant’s individual circumstances. Notwithstanding anything herein to the contrary, in the event the Committee determines that the Participant has accepted or intends to accept employment with a competitor of any business unit of the Corporation, the Vesting Percentage shall be zero. Following the Committee's determination under this Paragraph 7, the Participant shall be entitled to receive

a cash payment equal to the product of (x) the number of vested Performance Units, multiplied by (y) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's vesting determination under this Paragraph 7 and, in any event, on or before March 15, 2020. If, in accordance with the Committee's determination, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full. In the event of the Retirement of the Participant before completion of half of the Performance Cycle, the Participant's right to the Performance Units shall be forfeited in its entirety as of the date of his or her termination of employment, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

8.Vesting Upon a Change of Control. Notwithstanding anything herein to the contrary, upon the occurrence of a Change in Control prior to the end of the Performance Cycle, the Participant's right to receive the Performance Units, unless previously forfeited pursuant to Paragraph 5 or Paragraph 7 or vested pursuant to Paragraph 6, shall vest in full. The Vesting Percentage shall be calculated as provided under Paragraph 3, and the Payout Value for each Performance Unit shall be the applicable End Stock Price. A cash payment equal to the vested value of the Performance Units shall be made on the first day of the third month following the Change in Control; provided, however that if such Change in Control fails to qualify as a “change in control event” within the meaning of Treas. Regs. section 1.409A-3(i)(5), then the cash payment will be made during the first week of January 2020. Such vesting and the making of the related cash payment shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

9.Dividend Equivalents. With respect to each of the Performance Units granted under Paragraph 1, the Participant shall be credited with Dividend Equivalents equal to the amount per share of Common Stock of any ordinary cash dividends declared by the Board with record dates during the period beginning on the first day of the Performance Cycle and ending on the earliest to occur of: (a) the last day of the Performance Cycle, (b) the effective date of a Change in Control and (c) the date on which the Performance Units otherwise vest or are forfeited in accordance with Paragraphs 5, 6, 7 or 8. The Corporation shall pay in cash to the Participant an amount equal to (x) the sum of the aggregate amounts of such Dividend Equivalents credited to the Participant, if any, multiplied by (y) the Vesting Percentage that is applicable to the related Performance Units, with such amount to be paid as and when any cash payment with respect to the related Performance Units is paid. Any Dividend Equivalents shall be forfeited as and when the related Performance Units are forfeited in accordance with the terms of the Award Agreement.

10.Taxes. In all cases the Participant will be responsible to pay all required withholding taxes associated with the Performance Units.Pursuant to Section 10 of the Plan, the Corporation or its designated representative (which may be a Subsidiary) shall have the right to withhold applicable taxes from the cash otherwise payable to the Participant, or from other compensation payable to the Participant, at the

time of the vesting and delivery of such cash payment or to take such other action as may be necessary in the opinion of the Corporation to satisfy all obligations for withholding.

11.No Stockholder Rights. The Participant shall in no way be entitled to any of the rights of a stockholder of the Corporation as a result of this Award Agreement. Specifically, the Performance Units do not have voting rights.

12.Nonassignability. Upon the Participant's death, the Performance Units shall be paid out as provided in Paragraph 6 of this Award Agreement. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Performance Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Performance Units shall have no effect.

13.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Corporation or any Subsidiary or successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

14.Modification of Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Corporation, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant under this Award Agreement. Without the consent of the Participant, this Award Agreement may be amended or supplemented (i) to cure any ambiguity or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to add to the covenants and agreements of the Corporation for the benefit of the Participant or to add to the rights of the Participant or to surrender any right or power reserved to or conferred upon the Corporation in this Award Agreement; provided, in each case, that such changes or corrections shall not adversely affect the rights of the Participant under this Award Agreement without the Participant’s consent, or (iii) to make such other changes as the Corporation, upon advice of counsel, determines are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or governmental rule or regulation, including any applicable federal or state securities or tax laws.

15. Data Privacy. By accepting the Performance Units subject to the terms of this Award Agreement, the Participant hereby explicitly and unambiguously consents to the collection, use and transfer, in electronic or other form, of the Participant’s personal data, including but not limited to items of data described in this Paragraph 15, by and among Marathon Oil Corporation and its Subsidiaries and affiliates, including the Participant’s employer, (collectively referred to as “Marathon Oil” in this Paragraph 15) for the exclusive purpose of implementing, administering and managing the Participant’s participation in the Plan. The Participant understands and acknowledges that Marathon Oil holds certain personal data about the Participant, including, but not limited to, the Participant’s name, home address and telephone number, date of birth, social insurance number or other identification number, salary, nationality, job title, any shares of stock or directorships held in Marathon Oil, details of all grants or any other entitlement to salary and other

cash payments, and shares of stock or units awarded, canceled, forfeited, exercised, vested, unvested or outstanding in the Participant’s favor, for the purpose of implementing, administering and managing the Plan (which information is collectively referred to as “Data” for purposes of this Paragraph 15). The Participant understands and agrees that Data may be transferred to one or more third parties assisting Marathon Oil in the implementation, administration and management of the Plan, that these recipients may be located in the Participant’s country of citizenship, country of residence or elsewhere, and that the recipient’s country may have different data privacy laws and protections than the Participant’s country of citizenship or country of residence. The Participant understands that he or she may request a list with the names and addresses of any recipients of the Data by contacting his or her local human resources representative. The Participant, by acceptance of the Performance Units subject to the terms of this Award Agreement, authorizes the recipients to receive, possess, use, retain and transfer the Data, in electronic or other form, for the purposes of implementing, administering and managing the Participant’s participation in the Plan, including any requisite transfer of such Data as may be required to a broker or other third party with whom the Participant may elect to deposit shares or cash following the lapse of applicable restrictions, and reporting to applicable tax and other legal authorities. The Participant understands that he or she may, at any time, view the Data, request additional information about the storage and processing of the Data, require any necessary amendments to the Data to correct inaccuracy, or refuse or withdraw the consent provided herein, without cost, by contacting the Participant's local human resources representative in writing. The Participant understands that refusing or withdrawing the Participant’s consent may affect the Participant’s ability to participate in the Plan, and the Participant may obtain additional information about the consequences of refusing to consent or withdrawing consent by contacting his or her local human resources representative.

Marathon Oil Corporation

By:

Authorized Officer

EX-10.33

Exhibit 10.33

Marathon Oil Corporation

Officer Change in Control Severance Benefits Plan

(As amended effective January 1, 2018)

1.    Purpose of the Plan. Marathon Oil Corporation and its subsidiaries and affiliates recognize that the contributions of its officers to the growth and success of the Corporation (as defined below) are and will continue to be substantial, and the Corporation desires to assure the continued employment of its officers. In this connection, the Board of Directors of the Corporation (the “Board”) recognizes that, as is the case with many publicly-held corporations, the possibility of a change in control may exist and that such possibility, and the uncertainty and questions which it may raise among management, may result in the departure or distraction of management personnel to the detriment of the Corporation and its stockholders.

Accordingly, the Board has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of the Corporation’s officers to their assigned duties without distraction in the face of potentially disturbing circumstances arising from the possibility of a change in control of the Corporation.

In order to induce officers to remain in the employ of the Corporation, the Corporation has established this Marathon Oil Corporation Officer Change in Control Severance Benefits Plan (the “Plan”) as set forth herein.

This Plan is in accordance with the Policy Concerning Severance Agreements with Senior Executive Officers adopted by the Corporation that was originally effective February 1, 2005 and that was most recently amended and restated effective January 1, 2018.

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2.    Definitions. As used in the Plan, the following terms shall have the following meanings (and the singular includes the plural, unless the context clearly indicates otherwise):

Administrator: The Compensation Committee of the Board, provided that the Administrator may delegate its authority under this Plan pursuant to such conditions or limitations as the Administrator may establish.

Cause: A Separation from Service of the Employee by the Corporation upon (i) the willful and continued failure by the Employee to substantially perform the Employee’s duties with the Corporation (other than any such failure resulting from Separation from Service by the Employee for Good Reason or any such failure resulting from the Employee’s incapacity due to physical or mental illness), after a demand for substantial performance is delivered to the Employee that specifically identifies the manner in which the Corporation believes that the Employee has not substantially performed his or her duties, and the Employee has failed to resume substantial performance of his or her duties on a continuous basis within 14 days of receiving such demand, (ii) the willful engaging by the Employee in conduct which is demonstrably and materially injurious to the Corporation, monetarily or otherwise or (iii) the Employee’s conviction of a felony or conviction of a misdemeanor which impairs the Employee’s ability substantially to perform his or her duties with the Corporation. For purposes of Cause, no act, or failure to act, on the Employee’s part shall be deemed “willful” unless done, or omitted to be done, by the Employee not in good faith and without reasonable belief that the action or omission was in the best interest of the Corporation.

Change in Control of the Corporation and Change in Control: A change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i)    any person (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined

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in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation’s then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below); or

(ii)    the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on the date hereof, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest including, but not limited to, a consent solicitation, relating to the election of directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation’s stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the date hereof or whose appointment, election or nomination for election was previously so approved or recommended; or

(iii) there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of

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the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the shareholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation’s assets.

Code: The Internal Revenue Code of 1986, as amended.

Corporation: Marathon Oil Corporation and, where applicable, each related company or business which is part of the same controlled group under Code sections 414(b) or 414(c).

Disability or Disabled: The Employee’s incapacity due to physical or mental illness which in the opinion of a licensed physician renders the Employee incapable of performing his or her assigned duties with the Corporation, and shall be deemed to occur on the earlier of (i) the date that there is no reasonable expectation that the Participant will return to service with the Corporation or (ii) the date the Employee has been absent from the full-time performance of his or her duties with the Corporation for six consecutive months or more.

Employee: An Officer of the Corporation who is in salary grade 88 or above.

Excise Tax: The excise tax imposed by Code section 4999 (or any successor thereto).

Good Reason: Without the Employee’s express written consent, the occurrence within two years after a Change in Control, or within two years after and at the request of or as a result of actions by a third party who has taken steps reasonably calculated to effect a Change in Control, of any one or more of the following:

(i)    the assignment to the Employee of duties materially inconsistent with his or her position immediately prior to the Change in Control or a substantial reduction or alteration in the nature of the Employee’s position, duties, status or responsibilities from those in effect immediately prior to the Change in Control;

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(ii)    a reduction by the Corporation in the Employee’s annualized rate of base salary (“Base Salary”) as in effect immediately prior to the Change in Control;

(iii)     the Corporation’s requiring the Employee to be based at a location in excess of fifty miles from the location where the Employee was based immediately prior to the Change in Control;

(iv)     the failure by the Corporation (a) to continue to allow the Employee to participate in all of the Corporation’s employee benefit, incentive compensation, bonus, stock option and stock award plans, programs, policies, practices or arrangements in which officers of the Corporation participate on the same level at which other participants in such plans, programs, practices, policies or arrangements are allowed to participate or (b) to continue to provide the Employee with opportunity to receive compensation and benefits that do not represent a material reduction, either in terms of the amount of compensation and benefits provided or the level of the Employee’s participation relative to other participants, in the compensation and benefits provided immediately prior to the Change in Control;

(v)    the failure of the Corporation to obtain an agreement from any successor to the Corporation to assume and agree to perform this Plan, as contemplated in Section 6 hereof; and

(vi)     any purported Separation from Service by the Corporation of the Employee’s employment that is not effected pursuant to, and satisfying the requirements of, a Notice of Termination.

The Employee’s right to Separate from Service for Good Reason shall not be affected by his or her incapacity due to physical or mental illness. The Employee’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason hereunder. The Employee’s determination of the existence of Good Reason shall be final and conclusive unless such determination is not made in good faith and is made without reasonable belief in the existence of Good Reason.

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Notice of Termination: A written notice which indicates the specific reason(s) relied upon by the Corporation for Separation from Service of an Employee and which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for the Employee’s Separation from Service. Any Separation from Service by the Corporation for Cause or for Disability shall be communicated by Notice of Termination to the Employee, and or any Separation from Service by the Employee for Good Reason shall be communicated by Notice of Termination to the Corporation.

Plan: This Marathon Oil Corporation Officer Change in Control Severance Benefits Plan, effective as of the close of business on October 26, 2011 and amended effective October 28, 2014 and January 1, 2018, and as may be further amended from time to time.

Qualified Termination: An Employee has a Qualified Termination if he or she Separates from Service within two years after the date of a Change in Control unless such Separation from Service is (i) due to death or Disability, (ii) by the Corporation for Cause, (iii) by the Employee other than for Good Reason or (iv) on or after the date that the Employee attains age 65. If an Employee Separates from Service prior to a Change in Control and such Separation from Service is other than (w) due to death or Disability, (x) by the Corporation for Cause, (y) by the Employee other than for Good Reason or (z) on or after the date that the Employee attains age 65, the Employee will be deemed to have a Qualified Termination prior to a Change in Control so long as the Employee reasonably demonstrates that such Separation from Service was at the request of or as a result of actions by a third party who has taken steps reasonably calculated to effect a Change in Control.

Separation Date: The date that an Employee has a Separation from Service.

Separation from Service or Separate from Service: Separation from Service shall have the same meaning as set forth under Code section 409A with respect to the Corporation.

Severance Benefits: The benefits specified in Section 3(d) hereof that are due to an Employee who has a Qualified Termination.

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3.    Compensation upon Separation from Service or During Disability.

(a)    Disability. During any period following a Change in Control during which an Employee fails to perform his or her full-time duties with the Corporation as a result of incapacity due to physical or mental illness, such Employee’s total compensation, including Base Salary, bonus and any benefits, will continue unaffected until either such Employee’s Separation Date or such Employee returns to the full-time performance of his or her duties. In the event the Employee returns to the full-time performance of his or her duties prior to a Separation from Service, such Employee shall continue to receive his or her full Base Salary and bonus plus all other amounts to which such Employee is entitled under any compensation or other employee benefit plan of the Corporation without interruption. If an Employee is determined to be Disabled, the Corporation shall promptly cause the Employee to have a Separation from Service due to Disability. In the event of an Employee’s Separation from Service due to Disability, such Employee shall not be entitled to Severance Benefits under this Plan and such Employee’s benefits shall be determined in accordance with the Corporation’s retirement, insurance and other applicable programs and plans then in effect.

(b)    Separation from Service for Cause or Voluntary Separation from Service for Other Than Good Reason. If an Employee has a Separation from Service by the Corporation for Cause or by the Employee other than for Good Reason, the Corporation shall pay such Employee his or her full Base Salary through the Separation Date at the rate in effect at the time Notice of Termination is given, plus all other amounts to which such Employee is entitled under any compensation or benefit plan of the Corporation at the time such payments are due, and the Corporation shall have no further obligations to such Employee under this Plan.

(c)    Death. If an Employee has a Separation from Service by reason of his or her death, such Employee’s benefits shall be determined in accordance with the Corporation’s retirement, survivor’s benefits, insurance and other applicable

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programs and plans then in effect, and such Employee shall not be entitled to Severance Benefits under this Plan.

(d)    Qualified Termination. If an Employee has a Qualified Termination, he or she shall be entitled to the following Severance Benefits:

(i)    Accrued Compensation and Benefits. The Corporation shall provide to the Employee:

(A)    the Employee’s Base Salary accrued through the Separation Date to the extent not theretofore provided;

(B)    a lump sum cash amount equal to the value of the Employee’s unused vacation days accrued through the Separation Date; and

(C)    the Employee’s normal post-termination compensation and benefits under the Corporation’s retirement, insurance and other compensation and benefit plans as in effect immediately prior to the Separation Date, or if more favorable to the Employee, immediately prior to the Change in Control, which shall be paid at the time or times indicated pursuant to the terms of the plans or arrangements providing for such benefits.

(ii)    Lump Sum Severance Payment. The Corporation shall provide to the Employee a severance payment in the form of a cash lump sum distribution equal to the Employee’s Current Annual Compensation (as defined below) multiplied times three (3); provided, however, that if the Employee attains age 65 within three years of the Separation Date, the Employee’s benefit will be limited to a pro rata portion of such benefit based on a fraction equal to the number of full and partial months existing between the Separation Date and the Employee’s sixty-fifth (65^th) birthday divided by 36 months. For purposes of this Section 3(d), the term “Current Annual Compensation” shall mean the sum of:

(A)    the Employee’s Base Salary in effect immediately prior to the occurrence of the circumstances giving rise to such Separation from Service or, if higher, immediately prior to the Change in Control;

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(B)    an amount equal to the mean average of the annual bonuses awarded to the Employee for the immediately preceding three years, if any, under any annual bonus plan of the Corporation or its predecessor in the three (3) years immediately preceding the Separation Date or, if higher, in the three (3) years immediately preceding the Change in Control; and

(C)    an amount equal to the Employee’s annual bonus at target level multiplied by a fraction equal to the number of days in the bonus calculation year during which the Employee was employed divided by 365.

(iii)     Welfare Benefits Payment. The Corporation will pay the Employee an amount equal to the product of (A) eighteen (18), and (B) the monthly COBRA premium in effect at the Employee’s Separation Date for the level of coverage in which the Employee participated immediately prior to his or her Separation from Service.

(iv)    Timing. To the extent that payments under this Section 3(d) are not deferred compensation within the meaning of Code section 409A, and except as otherwise specifically stated herein, the payments provided for in this Section 3(d) shall be made not later than thirty days following the Separation Date. Notwithstanding any provision of the Plan to the contrary, if the Employee is a “specified employee” as determined by the Company in accordance with its established policy, any payments of deferred compensation within the meaning of Code section 409A payable to the Employee as a result of the Employee’s Separation from Service (other than as a result of death) which would otherwise be paid within six months of his or her Separation from Service shall be payable on the date that is one day after the earlier of (A) the date that is six months after the Employee’s Separation Date or (B) the date that otherwise complies with the requirements of Code section 409A. Each payment described herein is hereby designated as a “separate payment” for purposes of Code section 409A.

(e)    Legal Fees. The Corporation shall also pay to the Employee all legal fees and expenses incurred by the Employee, as such legal fees and expenses are incurred but no later than the end of the calendar year immediately following the calendar year for which such fees and expenses were incurred, as a result of Separation

9

from Service (including all such fees and expenses, if any, incurred in contesting or disputing any such Separation from Service or in seeking to obtain or enforce any right or benefit provided by this Plan or in connection with any tax audit or proceeding to the extent attributable to the application of Code section 409A or 4999 to any payment or benefit provided hereunder). The Employee’s right to such reimbursement payments under this provision shall not be subject to liquidation or exchange for any other payment or benefit.

(f)    No Mitigation. The Employee shall not be required to mitigate the amount of any payment provided for in this Section 3 by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section 3 be reduced by any compensation earned by the Employee as the result of employment by another employer, including self-employment, after the Separation Date, or otherwise.

4.    Incentive Awards.

(a)     General. This Section 4 shall not delay the vesting of any outstanding options, stock appreciation rights, stock awards and restricted stock awards or cash awards granted to the Employee under any option or incentive plan of the Corporation past the date when such awards would, by their terms have become vested. This Section 4 provides for accelerated vesting of awards that were granted prior to January 1, 2018 which, by their terms, would not become vested upon a Change in Control. This Section 4 does not accelerate vesting of awards that were granted during or after January 1, 2018. To the extent required for compliance with the requirements of Code section 409A, this Section 4 shall delay the settlement of any outstanding awards if such awards would have been settled upon a Change in Control.

(b)     Options, Stock Appreciation Rights, Stock Awards and Cash Awards. Upon a Change in Control all outstanding options, stock appreciation rights, stock awards, and restricted stock awards or cash awards granted to the Employee prior to January 1, 2018 under any option or incentive plan of the Corporation shall be immediately fully vested and immediately exercisable and shall remain so exercisable throughout their entire original terms, and all stock awards, restricted stock awards, and cash awards

10

granted prior to January 1, 2018 shall be immediately vested and, subject to Section 4(e) shall be settled upon vesting.

(c)    Restricted Stock Units. Upon a Change in Control all outstanding restricted stock unit awards granted to the Employee prior to January 1, 2018 shall be immediately vested. To the extent that immediate settlement of vested outstanding restricted stock units would result in an adverse tax consequence to an Employee under Code section 409A, then outstanding restricted stock units will (subject to Code section 4(e)) be settled upon the earliest to occur of (i) the date on which a change in ownership or change in effective control for purposes of Code section 409A occurs, (ii) the date on which the Employee has a Separation from Service or (iii) the date on which the restricted stock units would have been settled absent a Change in Control.

(d)    Separation Date Prior to Change in Control. If the Employee has a Separation from Service prior to a Change in Control, and the Employee is entitled to benefits under Section 3(d), then as of the Separation Date all outstanding options and stock appreciation rights granted to the Employee prior to January 1, 2018 shall be immediately fully vested and immediately exercisable and shall remain so exercisable throughout their entire original terms, and all stock awards, restricted stock awards, restricted stock unit awards and cash awards granted to the Employee prior to January 1, 2018 shall be immediately vested and, subject to Section 4(e), shall be settled upon vesting.

11

(e) Settlement of Deferred Compensation Awards. Notwithstanding any provision of the Plan or the applicable award agreement to the contrary, if the Employee is a “specified employee” as determined by the Company in accordance with its established policy, any settlement of awards described in this Section 4 that would be a payment of deferred compensation within the meaning of Code section 409A payable to the Employee as a result of the Employee’s Separation from Service (other than as a result of death) and which would otherwise be paid within six months of the Employee’s Separation Date shall be payable on the date that is one day after the earlier of (i) the date that is six months after the Employee’s Separation Date or (ii) the date that otherwise complies with the requirements of Code section 409A. Each payment described herein is hereby designated as a “separate payment” for purposes of Code section 409A.

5.    Potential Rollback to Avoid Excise Tax. Whether or not the Employee becomes entitled to any benefits under Section 3 above, in the event that there is made any payment in the nature of compensation to or for the Employee’s benefit that would be subject to the Excise Tax, the Corporation shall pay to the Employee, either the amount to which the Employee is entitled under the terms of this Plan or a reduced amount that will result in the Employee’s receiving a greater after-tax benefit due to avoidance of the Excise Tax. If a reduction in the payments to the Employee would result in a greater after-tax benefit to the Employee because of avoidance of the Excise Tax, then the amount of cash severance payable under Section 3(d)(ii) of this Plan shall be reduced first.

6.    Policy Concerning Severance Agreements with Senior Executive Officers. If an Employee under this Plan is a “Senior Executive Officer” as defined in the Corporation’s Policy Concerning Severance Agreements with Senior Executive Officers, then any cash severance payment under Section 3(d)(ii) of this Plan shall be reduced to the extent necessary to comply with such policy.

7. Successors.

12

(a)    Successors of Corporation. The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Corporation or of any division or subsidiary thereof employing the Employee to expressly assume and agree to perform this Plan in the same manner and to the same extent that the Corporation would be required to perform it if no such succession had taken place. Failure of the Corporation to obtain such assumption and agreement prior to the effectiveness of any such succession shall be a breach of this Plan and shall entitle the Employee to compensation from the Corporation in the same amount and on the same terms as the Employee would be entitled hereunder if the Employee had a Separation from Service for Good Reason following a Change in Control, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Separation Date.

(b)    Representatives and Heirs of Employee. This Plan shall inure to the benefit of and be enforceable by the Employee’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Employee should die while any amount would still be payable to the Employee hereunder if the Employee had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Plan to the Employee’s devisee, legatee or other designee or, if there is no such designee, to the Employee’s estate.

8.    Notice. For the purpose of this Plan, notices and all other communications provided for in the Plan shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the respective addresses set forth on the first page of this Plan.

9.    Choice of Law. The validity, interpretation, construction and performance of this Plan shall be governed by the laws of the State of Delaware.

13

10.    Validity. The invalidity or unenforceability of any provision of this Plan shall not affect the validity or enforceability of any other provision of this Plan, which shall remain in full force and effect.

11.    Claims and Arbitration. Any dispute or controversy arising under or in connection with this Plan shall be settled exclusively by arbitration in accordance with the rules of the American Arbitration Association then in effect. Judgment may be entered on the arbitrator’s award in any court having jurisdiction; provided, however, that the Employee shall be entitled to seek specific performance of his or her right to be paid until the Separation Date during the pendency of any dispute or controversy arising under or in connection with this Plan. Any such arbitration shall be held in Houston, Texas.

12.    Plan Amendment and Termination. The Corporation may at any time amend or terminate this Plan, provided that for a period of two (2) years following a Change in Control, the Plan may not be amended in a manner adverse to an Employee with respect to that Change in Control. Any amendment or termination shall be set out in an instrument in writing and executed by an appropriate officer of the Corporation.

13.    Entire Plan. Except as specifically modified, waived or discharged in an individual agreement between an Employee and the Corporation, this Plan supersedes any other agreement or understanding between the parties hereto with respect to the issues that are the subject matter of this Plan.

14

EX-12.1

Exhibit 12.1

MARATHON OIL CORPORATION

Computation of Ratio of Earnings to Fixed Charges (Unaudited)

	Year Ended
	December 31,
(In millions)	2017			2016			2015			2014			2013
Income (loss) from continuing operations before income taxes	$	(454	)	$	(1,164	)	$	(2,439	)	$	1,021		$	2,104
Income from equity method investments	256			175			145			424			423
Income (loss) from continuing operations before income taxes and income from equity method investments	(710		)	(1,339		)	(2,584		)	597			1,681
Add (deduct)
Fixed charges	357			421			382			352			360
Capitalized interest	(4		)	(23		)	(26		)	(33		)	(27		)
Amortization of capitalized interest	9			7			5			8			21
Distributed income from equity investees	276			192			178			454			430
Earnings as defined	(72		)	(742		)	(2,045		)	1,378			2,465
Net interest expense (including discontinued operations)	323			367			321			277			297
Capitalized interest (including discontinued operations)	4			23			26			33			27
Interest portion of rental expense (including discontinued operations)	30			31			35			42			36
Fixed charges as defined	357			421			382			352			360
Ratio of earnings to fixed charges	(0.20		)	(1.76		)	(5.35		)	3.91			6.85
Amount by which earnings were insufficient to cover fixed charges	$	429		$	1,163		$	2,427		$	—		$	—

* We closed the sale of our Angola assets in the first quarter of 2014, the sale of our Norway business in the fourth quarter of 2014 and the sale of our Canadian business in the second quarter of 2017. All previous periods have been recast to reflect these businesses as discontinued operations.

EX-21.1

Subsidiaries of Marathon Oil Exhibit 21.1

The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w).

Company Name	Country	Country Region
Alba Associates LLC	Cayman Islands
Alba Equatorial Guinea Partnership, L.P.	United States	Delaware
Alba Plant LLC	Cayman Islands
AMPCO Marketing, L.L.C.	United States	Michigan
AMPCO Services, L.L.C.	United States	Michigan
Atlantic Methanol Associates LLC	Cayman Islands
Atlantic Methanol Production Company LLC	Cayman Islands
E.G. Global LNG Services, Ltd.	United States	Delaware
Equatorial Guinea LNG Company, S.A.	Equatorial Guinea
Equatorial Guinea LNG Holdings Limited	Bahamas
Equatorial Guinea LNG Operations, S.A.	Equatorial Guinea
Equatorial Guinea LNG Train 1, S.A.	Equatorial Guinea
Marathon E.G. Alba Limited	Cayman Islands
Marathon E.G. Holding Limited	Cayman Islands
Marathon E.G. International Limited	Cayman Islands
Marathon E.G. LNG Holding Limited	Cayman Islands
Marathon E.G. LPG Limited	Cayman Islands
Marathon E.G. Offshore Limited	Cayman Islands
Marathon E.G. Production Limited	Cayman Islands
Marathon Eagle Ford Midstream LLC	United States	Delaware
Marathon East Texas Holdings LLC	United States	Delaware
Marathon International Oil Company	United States	Delaware
Marathon International Oil Holdings LLC	United States	Delaware
Marathon International Oil Libya Limited	Cayman Islands
Marathon Offshore Alpha Limited	Cayman Islands
Marathon Oil (East Texas) L.P.	United States	Texas
Marathon Oil (West Texas) L.P.	United States	Texas
Marathon Oil Company	United States	Ohio
Marathon Oil Corporation	United States	Delaware
Marathon Oil Dutch Holdings Coöperatief U.A.	Netherlands
Marathon Oil EF LLC	United States	Delaware
Marathon Oil EF II LLC	United States	Delaware
Marathon Oil Holdings (Barbados) Inc.	Barbados
Marathon Oil International Holding C.V.	Netherlands
Marathon Oil Investment LLC	United States	Delaware
Marathon Oil Permian LLC	United States	New Mexico
Marathon Oil U.K. LLC	United States	Delaware
Marathon West Texas Holdings LLC	United States	Delaware
MOC Portfolio Delaware, Inc.	United States	Delaware
Pan Ocean Energy LLC	United States	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements listed below of Marathon Oil Corporation of our report dated February 22, 2018 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

Form S-3ASR:	Relating to:
Reg. No	333-215733	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan
	333-211611	Marathon Oil Corporation 2016 Incentive Compensation Plan

/s/PricewaterhouseCoopers LLP

Houston, Texas     

February 22, 2018

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements listed below of Marathon Oil Corporation of our report dated February 22, 2018 relating to the financial statements of Alba Plant LLC, which appears as an exhibit in this Form 10-K.

Form S-3ASR:	Relating to:
Reg. No	333-215733	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan
	333-211611	Marathon Oil Corporation 2016 Incentive Compensation Plan

/s/PricewaterhouseCoopers LLP

Houston, Texas     

February 22, 2018

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company"), to our summary reports on evaluations of the estimated quantities of certain proved reserves of oil and gas, net to the Company's interest, and to such reports and this consent being filed as exhibits to this Form 10-K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

Form S-3ASR:	Relating to:
Reg. No.	333-215733	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan
	333-211611	Marathon Oil Corporation 2016 Incentive Compensation Plan

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

“Originally Signed by”

Tim R. Freeborn, P. Eng.

Vice President

Dated: February 22, 2018

Calgary, Alberta

CANADA

4100, 400 - 3rd Ave SW Calgary, AB, Canada T2P 4H2 teI 403-266-9500 gIjpc.com

EX-23.4

Exhibit 23.4

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company"), to our summary reports on audits of the estimated quantities of certain proved reserves of oil and gas, net to the Company's interest, and to such reports and this consent being filed as exhibits to this Form 10-K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

Form S-3ASR:	Relating to:
Reg. No.	333-215733	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan
	333-211611	Marathon Oil Corporation 2016 Incentive Compensation Plan

/s/ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Registration No. F-1580

Houston, Texas

February 22, 2018

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

EX-23.5

Exhibit 23.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company") to our summary reports on the estimated quantities of certain proved reserves of oil and gas and to such reports and this consent being filed as exhibits to this Form 10‑K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

Form S-3ASR:	Relating to:
Reg. No.	333-215733	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
Reg. No.	333-29709	Marathon Oil Company Thrift Plan
Reg. No.	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
Reg. No.	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
Reg. No.	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan
Reg. No.	333-211611	Marathon Oil Corporation 2016 Incentive Compensation Plan

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

February 22, 2018

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

Exhibit 31.1 

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Lee M. Tillman, certify that: 

1. I have reviewed this report on Form 10-K of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 22, 2018	/s/ Lee M. Tillman
		Lee M. Tillman
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2 

MARATHON OIL CORPORATION 

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002 

I, Dane E. Whitehead, certify that:

1. I have reviewed this report on Form 10-K of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 22, 2018	/s/ Dane E. Whitehead
		Dane E. Whitehead
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Marathon Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee M. Tillman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 22, 2018

/s/ Lee M. Tillman

Lee M. Tillman

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Marathon Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dane E. Whitehead, Chief Financial Officer, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 22, 2018

/s/ Dane E. Whitehead

Dane E. Whitehead

Executive Vice President and Chief Financial Officer

EX-99.2

Exhibit 99.2

MARATHON OIL CORPORATION

MID-CONTINENT AREA

Estimated

Future Reserves

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2016

/s/ Scott J. Wilson

Scott J. Wilson, P.E., M.B.A.

Colorado License No. 36112

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (303) 623-4258
621 SEVENTEENTH STREET SUITE 1550	DENVER, COLORADO 80293	TELEPHONE (303) 623-9147

January 8, 2018

Marathon Oil Corporation

5555 San Felipe

P.O. Box 3128

Houston, Texas 77253-3128

Gentlemen:

At the request of Marathon Oil Corporation (Marathon), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by Marathon’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 8, 2018 and presented herein, was prepared for public disclosure by Marathon in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Marathon’s estimated net reserves attributable to the leasehold interests in certain properties owned by Marathon and reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate Marathon’s reserve determinations and are located in the states of Montana and North Dakota.

The properties reviewed by Ryder Scott account for a portion of Marathon’s total net proved reserves as of December 31, 2016. The properties reviewed by Ryder Scott and included in this letter were limited to Marathon’s Mid-Continent Area assets as specified by Marathon.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations

1100 LOUISIANA STREET, SUITE 4600    HOUSTON, TEXAS 77002-5294    TEL (713) 651-9191    FAX (713) 651-0849

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Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 2

and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Marathon has informed us that in the preparation of their reserve projections, as of December 31, 2016, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Marathon attributable to Marathon's interest in properties that we reviewed are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests – Mid-Continent Assets of

Marathon Oil Corporation

As of December 31, 2016

	Proved
	Developed Producing	Undeveloped	Total Proved
Audited by Ryder Scott Net Reserves
Oil/Condensate – MBarrels	13,469	22,636	36,105
Plant Products – MBarrels	20,873	30,674	51,547
Gas – MMCF	220,163	278,333	498,496

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

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the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Marathon’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 4

not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Marathon, for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Marathon and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by analogy.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Marathon relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Marathon for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period

The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Marathon for the geographic area(s) reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 5

The product prices which were actually used by Marathon to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon.

The table below summarizes Marathon’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Marathon’s “average realized prices.” The average realized prices shown in the table below were determined from Marathon’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Marathon’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$42.75/Bbl	$41.04/Bbl
United States	NGLs	WTI Cushing	$42.75/Bbl	$15.22/Bbl
	Gas	Henry Hub	$2.49/MMBTU	$2.50/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Marathon’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Marathon are based on the operating expense reports of Marathon and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. Additional gathering and transportation fees were included in the operating costs. The operating costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Marathon are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. The estimated net cost of abandonment after salvage was included by Marathon for properties where abandonment costs net of salvage were significant. Marathon’s estimates of the net abandonment costs were accepted without independent verification. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Marathon’s estimate.

The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Marathon’s plans to develop these reserves as of December 31, 2016. The

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 6

implementation of Marathon’s development plans as presented to us is subject to the approval process adopted by Marathon’s management. As the result of our inquiries during the course of our review, Marathon has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Marathon’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Marathon. Additionally, Marathon has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Marathon were held constant throughout the life of the properties.

Marathon’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Marathon to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Marathon. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Marathon’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Marathon’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Marathon owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Marathon for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Marathon are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 7

We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Marathon has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Marathon’s forecast of future proved production, we have relied upon data furnished by Marathon with respect to property interests owned, production from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Marathon. We consider the factual data furnished to us by Marathon to be appropriate and sufficient for the purpose of our review of Marathon’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Marathon and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Marathon in their estimation of proved reserves to be effective and we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Marathon's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Marathon's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Marathon when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Marathon.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 8

authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Marathon. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Marathon.

Marathon makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Marathon has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-Kis incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of Marathon of the references to our name as well as to the references to our third party report for Marathon, which appears in the December 31, 2016 annual report on Form 10-K of Marathon. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Marathon.

We have provided Marathon with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Marathon and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation - Mid-Continent Area

January 8, 2018

Page 9

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Scott J. Wilson

Scott J. Wilson, PE, MBA

Colorado License No. 36112

        Senior Vice President            [SEAL]

SJW (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 2000, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at https://www.ryderscott.com/company/employees/denver-employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one chapter in Marine and Petroleum Geology and two in SPEE monograph 4, which was published in 2016. He is the primary inventor on four US patents and won the 2017 Reservoir Description and Dynamics award for the SPE Rocky Mountain Region.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.3

Exhibit 99.3

MARATHON OIL CORPORATION

EAGLE FORD

Estimated

Future Reserves

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2016

/s/ Daniel R. Olds	/s/ Syed R. Rizvi
Daniel R. Olds, P.E.	Syed R. Rizvi
TBPE License No. 60996	Petroleum Engineer
Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

January 11, 2018

Marathon Oil Corporation

5555 San Felipe

P.O. Box 3128

Houston, Texas 77253-3128

Gentlemen:

At the request of Marathon Oil Corporation (Marathon), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by Marathon’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 8, 2018 and presented herein, was prepared for public disclosure by Marathon in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Marathon’s estimated net reserves attributable to the leasehold interests in certain properties owned by Marathon and reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate Marathon reserve determinations and are located in the state of Texas.

The properties reviewed by Ryder Scott account for a portion of Marathon’s total net proved reserves as of December 31, 2016. The properties reviewed by Ryder Scott and included in this letter were limited to Marathon‘s Eagle Ford assets as specified by Marathon.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Marathon has informed us that in the preparation of their reserve projections, as of December 31, 2016, they used

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 2

average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Marathon attributable to Marathon's interest in properties that we reviewed are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests – Eagle Ford Assets of

Marathon Oil Corporation

As of December 31, 2016

	Proved
	Developed Producing	Undeveloped	Total Proved
Audited by Ryder Scott Net Reserves
Oil/Condensate – MBarrels	103,971	146,306	250,277
Plant Products – MBarrels	42,450	45,623	88,073
Gas – MMCF	235,405	264,827	500,232

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Marathon’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 3

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 4

The proved reserves, prepared by Marathon, for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Marathon and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by analogy.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Marathon relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Marathon for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period..

The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Marathon for the geographic area reviewed by us.

The product prices which were actually used by Marathon to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon.

The table below summarizes Marathon’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Marathon’s “average realized prices.” The average realized prices shown in the table below were determined from Marathon’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Marathon’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 5

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$42.75/Bbl	$38.75/Bbl
United States	NGLs	Mont Belvieu, TX	$19.97/Bbl	$28.89/Bbl
	Gas	Henry Hub	$2.49/MMBTU	$2.09/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Marathon’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Marathon are based on the operating expense reports of Marathon and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. Additional gathering and transportation fees were included in the operating costs. The operating costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Marathon are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. The estimated net cost of abandonment after salvage was included by Marathon for properties where abandonment costs net of salvage were significant. Marathon’s estimates of the net abandonment costs were accepted without independent verification. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Marathon’s estimate.

The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Marathon’s plans to develop these reserves as of December 31, 2016. The implementation of Marathon’s development plans as presented to us is subject to the approval process adopted by Marathon’s management. As the result of our inquiries during the course of our review, Marathon has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Marathon’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Marathon. Additionally, Marathon has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Marathon were held constant throughout the life of the properties.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 6

Marathon’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Marathon to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Marathon. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Marathon’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Marathon’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Marathon owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Marathon for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Marathon are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Marathon has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Marathon’s forecast of future proved production, we have relied upon data furnished by Marathon with respect to property interests owned, production from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Marathon. We consider the factual data furnished to us by Marathon to be appropriate and sufficient for the purpose of our review of Marathon’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Marathon and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 7

that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Marathon in their estimation of proved reserves to be effective and we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Marathon's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Marathon's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Marathon when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Marathon.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Marathon. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 8

technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Marathon.

Marathon makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Marathon has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-Kis incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of Marathon of the references to our name as well as to the references to our third party report for Marathon, which appears in the December 31, 2016 annual report on Form 10-K of Marathon. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Marathon.

We have provided Marathon with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Marathon and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Eagle Ford

January 11, 2018

Page 9

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Daniel R. Olds

Daniel R. Olds, P.E.

TBPE License No. 60996

Managing Senior Vice President    [SEAL]

/s/ Syed R. Rizvi

Syed R. Rizvi

Petroleum Engineer

DRO-SRR (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Daniel R. Olds was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income prepared by Ryder Scott presented herein.

Mr. Olds, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2001, is a Managing Senior Vice President and also serves as an Engineering Group Coordinator responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  He is a member of Ryder Scott’s Board of Directors.  Before joining Ryder Scott, Mr. Olds served in a number of engineering and evaluation positions with PricewaterhouseCoopers, Wintershall Oil and Gas Company and Cities Service Oil Company.  For more information regarding Mr. Olds’ geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Olds earned a Bachelor of Science degree in Petroleum Engineering from West Virginia University in 1981, an MBA from the University of Houston in 1991 and is a licensed Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Evaluation Engineers (past president) and the Society of Petroleum Engineers. He currently serves on the SPE Oil and Gas Reserves Committee.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Olds fulfills. For 2017, Mr. Olds had over 40 hours of continuing education hours related to reserves, reserve evaluation, and ethics.  Mr. Olds has had at least 30 hours of continuing education for each of the last 5 years.

Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Olds has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) 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.

(ii) Undrilled locations can be classified as having undeveloped reserves only 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.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.4

Exhibit 99.4

MARATHON OIL CORPORATION

BAKKEN

Estimated

Future Reserves

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2016

/s/ James L. Baird	/s/ Clark D. Parrott
James L. Baird, P.E.	Clark D. Parrott, P.E.
Colorado License No. 41521	Colorado License No. 35262
Managing Senior Vice President	Senior Petroleum Engineer

[SEAL]                             [SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (303) 623-4258
621 SEVENTEENTH STREET SUITE 1550	DENVER, COLORADO 80293	TELEPHONE (303) 623-9147

January 8, 2018

Marathon Oil Corporation

5555 San Felipe

P.O. Box 3128

Houston, Texas 77253-3128

Gentlemen:

At the request of Marathon Oil Corporation (Marathon), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by Marathon’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our reserves audit, completed on January 8, 2018 and presented herein, was prepared for public disclosure by Marathon in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Marathon’s estimated net reserves attributable to the leasehold interests in certain properties owned by Marathon and reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate Marathon reserve determinations and are located in the states of Montana and North Dakota.

The properties reviewed by Ryder Scott account for a portion of Marathon’s total net proved reserves as of December 31, 2016. The properties reviewed by Ryder Scott and included in this letter were limited to Marathon‘s Bakken assets as specified by Marathon.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or Reserves Information prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities and/or Reserves Information.” Reserves Information may consist of various estimates pertaining to the extent and value of petroleum properties.

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

1100 LOUISIANA STREET, SUITE 4600    HOUSTON, TEXAS 77002-5294    TEL (713) 651-9191    FAX (713) 651-0849

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

Marathon Oil Corporation – Bakken

January 8, 2018

Page 2

The estimated reserves presented in this report are related to hydrocarbon prices. Marathon has informed us that in the preparation of their reserve projections, as of December 31, 2016, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Marathon attributable to Marathon's interest in properties that we reviewed are summarized below:

SEC PARAMETERS

Estimated Net Reserves

Certain Leasehold Interests – Bakken Assets of

Marathon Oil Corporation

As of December 31, 2016

	Proved
	Developed Producing	Undeveloped	Total Proved
Audited by Ryder Scott Net Reserves
Oil/Condensate – MBarrels	108,707	154,983	263,690
Plant Products – MBarrels	11,247	15,564	26,811
Gas – MMCF	70,913	96,536	167,449

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty

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January 8, 2018

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in their recoverability. At Marathon’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered,could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Bakken

January 8, 2018

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in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves, prepared by Marathon, for the properties that we reviewed were estimated by performance methods, analogy, or a combination of methods. Approximately 100 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis which utilized extrapolations of historical production and pressure data available through December 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Marathon and were considered sufficient for the purpose thereof.

Approximately 100 percent of the proved undeveloped reserves that we reviewed were estimated by analogy.

To estimate economically recoverable proved oil and gas reserves, many factors and assumptions are considered including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Marathon relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Marathon for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period..

The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Marathon for the geographic area reviewed by us.

The product prices which were actually used by Marathon to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon.

The table below summarizes Marathon’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Marathon’s “average realized prices.” The average realized prices shown in the table below were determined from Marathon’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Marathon’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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January 8, 2018

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shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
	Oil/Condensate	WTI Cushing	$42.75/Bbl	$38.75/Bbl
United States	NGLs	WTI Cushing	$42.75/Bbl	$28.89/Bbl
	Gas	Henry Hub	$2.49/MMBTU	$2.09/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Marathon’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Marathon are based on the operating expense reports of Marathon and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. Additional gathering and transportation fees were included in the operating costs. The operating costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Marathon are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. The estimated net cost of abandonment after salvage was included by Marathon for properties where abandonment costs net of salvage were significant. Marathon’s estimates of the net abandonment costs were accepted without independent verification. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Marathon’s estimate.

The proved undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Marathon’s plans to develop these reserves as of December 31, 2016. The implementation of Marathon’s development plans as presented to us is subject to the approval process adopted by Marathon’s management. As the result of our inquiries during the course of our review, Marathon has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Marathon’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Marathon. Additionally, Marathon has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Marathon were held constant throughout the life of the properties.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Bakken

January 8, 2018

Page 6

Marathon’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Marathon to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Marathon. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Marathon’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Marathon’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a review of the properties in which Marathon owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Marathon for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Marathon are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Marathon has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Marathon’s forecast of future proved production, we have relied upon data furnished by Marathon with respect to property interests owned, production from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Marathon. We consider the factual data furnished to us by Marathon to be appropriate and sufficient for the purpose of our review of Marathon’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Marathon and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Bakken

January 8, 2018

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that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards. Ryder Scott found the processes and controls used by Marathon in their estimation of proved reserves to be effective and we found no bias in the utilization and analysis of data in estimates for these properties.

We were in reasonable agreement with Marathon's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Marathon's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Marathon when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Marathon.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Marathon. Neither we nor any of our employees have any financial interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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January 8, 2018

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technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Marathon.

Marathon makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Marathon has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-Kis incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of Marathon of the references to our name as well as to the references to our third party report for Marathon, which appears in the December 31, 2016 annual report on Form 10-K of Marathon. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Marathon.

We have provided Marathon with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Marathon and the original signed report letter, the original signed report letter shall control and supersede the digital version.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Marathon Oil Corporation – Bakken

January 8, 2018

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ James L. Baird        

James L. Baird, P.E.

Colorado License No. 41521

Managing Senior Vice President    [SEAL]

/s/ Clark D. Parrott

Clark D. Parrott, P.E.

Colorado License No. 35262

Senior Petroleum Engineer        [SEAL]

JLB-CDP (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. James Larry Baird was the primary technical person responsible for overseeing the estimate of the reserves.

Mr. Baird, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and also serves as Manager of the Denver office, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Baird served in a number of engineering positions with Gulf Oil Corporation (1970-1973), Northern Natural Gas (1973-1975) and Questar Exploration & Production (1975-2006). For more information regarding Mr. Baird’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Baird earned a Bachelor of Science degree in Petroleum Engineering from the University of Missouri at Rolla in 1970. He is a registered Professional Engineer in the States of Colorado and Utah. He is also a Legion of Honor member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, several State Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Baird fulfills as part of his registration in two states. As part of his continuing education, Mr. Baird attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Baird attends additional hours of formalized internal and external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, various analysis software and ethics for consultants.

Based on his educational background, professional training and more than 48 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Baird has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

EX-99.7

Exhibit 99.7

November 20, 2017

Marathon Oil Corporation

5555 San Felipe Street

Houston, Texas 77056

Ladies and Gentlemen:

In accordance with your request, we have prepared a reserves certification and deliverability analysis, as of December 31, 2016, for Alba Field, located offshore Equatorial Guinea. Pursuant to the terms of the Gas Purchase and Sales Agreement (GPSA) between the Alba Field production sharing contract (PSC) contractors (referred to herein as the "Alba Field owners") and Atlantic Methanol Production Company (AMPCO), the primary purpose of this report is to verify, using field downtime and gas disposition assumptions specified by Marathon Oil Corporation (Marathon), that there are (1) sufficient proved reserves in Alba Field to cover delivery of gas from the Alba Field owners to AMPCO equal to 100 percent of the maximum daily contract quantity over the remaining term of the GPSA that ends May 3, 2026, and (2) sufficient proved developed reserves in Alba Field to deliver, for a period of five years, 102 percent of the maximum daily contract quantity. As of December 31, 2016, all of the proved reserves in Alba are proved developed, so we have made a single forecast that assumes delivery of 102 percent of the maximum daily contract quantity for five years and 100 percent thereafter. The maximum daily contract quantity stipulated in the most recent amendment to the GPSA is 145,000 MMBTU per day, but the annual average daily contract quantity shall not exceed 135,000 MMBTU per day, or approximately 139 million cubic feet of gas per day (MMCFD). Our certification honors the annual average daily contract quantity. Economic analysis was performed only to confirm economic producibility and determine economic limits for the properties. The economic life of the field is the earlier of the economic limit and the end of the GPSA, May 3, 2026. Monetary values shown in this report are expressed in United States dollars ($).

We completed our evaluation on or about April 21, 2017. It is our understanding that Marathon's share of the gross (100 percent) proved reserves estimated in this report constitute approximately 11 percent of all proved reserves owned by Marathon. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Marathon's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose, provided that, as required by the SEC, Marathon lists its net interest after application of the PSC terms.

We estimate the gross (100 percent) reserves in Alba Field, as of December 31, 2016, to be:

	Gross (100%) Reserves
	Gas	Condensate	LPG
Category	(BCF)	(MMBBL)	(MMBBL)
Proved Developed	1,664	72	41

Gas volumes are dry gas and are expressed in billions of cubic feet (BCF) at standard temperature and pressure bases. Condensate and liquefied petroleum gas (LPG) volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons.

The estimates shown in this report are for proved developed reserves. The proved developed reserves are inclusive of proved developed producing and proved developed non-producing reserves. Our study indicates that there are no proved undeveloped reserves for these properties at this time. No study was made to determine whether probable

or possible reserves might be established for these properties. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk. In this report, we have attributed estimated gas sales volumes and LPG reserves to Alba Field, even though the LPG plant is separate from the field facilities. This designation is based on our interpretation of the agreement between the Alba Field owners and the LPG plant owners that states that title to the feedstock gas sales volumes and LPG liquids is transferred from the Alba Field owners at the tailgate of the LPG plant and that those volumes are valued on an MMBTU basis. It is our understanding that this interpretation is consistent with Marathon's internal reserves booking practice for Alba Field.

In order to satisfy the primary objective of this report, we made certain assumptions regarding future field production and injection rates. The assumption that we have varied in this report pertains to the feed rate of Alba Field gas to the liquefied natural gas (LNG) plant. Three LNG plant feed scenarios have been considered: a low-take case with a maximum feed rate of 560 MMCFD, a mid-take case with a maximum feed rate of 600 MMCFD, and a high-take case with a maximum feed rate of 640 MMCFD. The estimates of reserves shown in this report are based on the high-take case because this case is the most representative of current operating conditions. For the purposes of this report, we define the period during which all forecasted supply targets can be met to be the supply plateau period.

For all cases, following the end of the supply plateau period we have reduced supply to the LNG plant prior to reducing supply to the AMPCO methanol plant. Our estimates are based on monthly or annual gas rate constraints and monthly or annual downtime averages and do not account for any operational or contractual issues that may arise on a day-to-day basis throughout the year. These rate constraints and downtime averages vary monthly through 2018 and annually thereafter. For all three LNG plant feed scenarios, we have determined that there are (1) sufficient proved reserves to supply the AMPCO methanol plant with the maximum daily contract quantity until termination of the GPSA and (2) sufficient proved developed reserves to supply the AMPCO methanol plant with 102 percent of the maximum daily contract quantity for a period of five years.

Gas, condensate, and LPG prices were used only to confirm economic producibility and determine economic limits for the properties. The gas price used is the fixed contract price of $0.250 per MMBTU and is adjusted for energy content. Condensate and LPG prices are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2016. The average Dated Brent spot price of $43.53 per barrel is adjusted for quality and market differentials. The adjusted product prices of $0.243 per MCF of gas, $43.39 per barrel of condensate, and $31.50 per barrel of LPG are held constant throughout the lives of the properties.

Costs were used only to confirm economic producibility and determine economic limits for the properties. Operating costs used in this report are based on operating expense records of Marathon, the operator of the properties. As requested, operating costs are limited to direct plant- and field-level costs and Marathon's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into plant-level costs, PSC-level costs, platform-level costs, and per-unit-of-production costs. Capital costs used in this report were provided by Marathon and are based on its internal planning budgets. Capital costs are included as required for recurring maintenance projects. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Operating costs and capital costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties. We have made no investigation of any firm transportation contracts that may be in place for these properties; no adjustments have been made to our estimates to account for such contracts.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or

decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Marathon, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests.The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Marathon; Noble Energy, Inc.; and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the contractual rights to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Zachary R. Long, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

			NETHERLAND, SEWELL & ASSOCIATES, INC.
			Texas Registered Engineering Firm F-2699
		By:	/s/ C.H. (Scott) Rees III
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
By:	/s/ John R. Cliver	By:	/s/ Zachary R. Long
	John R. Cliver, P.E. 107216		Zachary R. Long, P.G. 11792
	Vice President		Vice President
	Date Signed: November 20, 2017		Date Signed: November 20, 2017

JRC:NFH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods

Definitions - Page 3 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

Definitions - Page 4 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

Definitions - Page 5 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.    Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.    Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Definitions - Page 6 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i) 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.

(ii) Undrilled locations can be classified as having undeveloped reserves only 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.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•     The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

•     The company's historical record at completing development of comparable long-term projects;

•     The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•     The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•     The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Definitions - Page 7 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 8 of 7

EX-99.9

Exhibit 99.9

Alba Plant LLC

Financial Statements

December 31, 2017 and 2016

Alba Plant LLC

Index

December 31, 2017 and 2016

	Page(s)
Independent Auditor’s Report	1
Financial Statements
Balance Sheets	2
Statements of Income	3
Statements of Stockholders’ Equity	4
Statements of Cash Flows	5
Notes to Financial Statements	6-11

Independent Auditor’s Report

To theManagement of Alba Plant LLC:

We have audited the accompanying financial statements of Alba Plant LLC, which comprise the balance sheets as of December 31, 2017 and 2016, and the related statements of income, stockholders’ equity, and cash flows for the years then ended.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position at December 31, 2017 and 2016, and the results of its operations and itscash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of matter

As discussed in Note 6 to the financial statements, the Company has entered into significant transactions with certain related parties. Our opinion is not modified with respect to this matter.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 22, 2018

Alba Plant LLC

Balance Sheets

December 31, 2017 and 2016

(in thousands of dollars)	2017		2016
Assets
Cash and cash equivalents	$	142,449	$	77,459
Accounts receivable	29,607		30,512
Accounts receivable–related parties	14,731		10,858
Inventory	37,693		37,037
Total current assets	224,480		155,866
Facility cost	567,667		567,615
Less: Accumulated depreciation	335,096		323,863
Net facility cost	232,571		243,752
Total assets	$	457,051	$	399,618
Liabilities and Stockholders' Equity
Accounts payable and accrued liabilities–related parties	7,053		6,991
Accrued government royalty–net profit interest	28,377		17,536
Foreign income taxes payable	74,322		35,935
Total current liabilities	109,752		60,462
Net Deferred tax liability	46,845		40,018
Stockholders' equity
Common stock - 1,000 shares issued and outstanding	1		1
(par value $1.00 per share, 50,000 shares authorized)
Retained earnings	300,453		299,137
Total stockholders' equity	300,454		299,138
Total liabilities and stockholders' equity	$	457,051	$	399,618

The accompanying notes are an integral part of these financial statements.

2

Alba Plant LLC

Statements of Income

Years Ended December 31, 2017 and 2016

(in thousands of dollars)	2017		2016
Revenues
Plant products	$	298,923	$	186,754
Plant products–related parties	799		931
Condensate–related parties	131,923		102,687
Other income	962		850
Other income–related parties	286		271
Total revenues	432,893		291,493
Expenses
Direct operating–related parties	37,331		47,929
Depreciation and amortization	11,233		26,555
General and administrative–related parties	28,165		28,770
Government royalty–net profit interest	28,380		17,536
Shipping and handling–related parties	3,543		4,088
Total expenses	108,652		124,878
Income from operations	324,241		166,615
Interest income	227		—
Income before income taxes	324,468		166,615
Income tax expense	81,152		41,637
Net income	$	243,316	$	124,978

The accompanying notes are an integral part of these financial statements.

3

Alba Plant LLC

Statements of Stockholders' Equity

Years Ended December 31, 2017 and 2016

							Total
	Common Stock			Retained			Stockholders'
(in thousands)	Shares	Amount		Earnings			Equity
Balances at December 31, 2015	1	$	1	$	316,159		$	316,160
Net income				124,978			124,978
Dividends				(142,000		)	(142,000		)
Balances at December 31, 2016	1	1		299,137			299,138
Net income				243,316			243,316
Dividends				(242,000		)	(242,000		)
Balances at December 31, 2017	1	$	1	$	300,453		$	300,454

The accompanying notes are an integral part of these financial statements.

4

Alba Plant LLC

Statements of Cash Flows

Years Ended December 31, 2017 and 2016

(in thousands of dollars)	2017			2016
Operating activities
Net income	$	243,316		$	124,978
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	11,233			26,555
Deferred income tax	6,827			5,723
Changes in:
Accounts receivable and accounts receivable-related parties	(2,968		)	(16,518		)
Prepayments	—			1,299
Inventory	(656		)	5,883
Accounts payable and accrued liabilities-related parties	75			(5,668		)
Accrued government royalty–net profit interest	10,841			804
Foreign income taxes payable	38,387			6,618
Net cash provided by operating activities	307,055			149,674
Investing activities
Capital expenditures	(65		)	(120		)
Net cash used in investing activities	(65		)	(120		)
Financing activities
Dividends	(242,000		)	(142,000		)
Net cash used in financing activities	(242,000		)	(142,000		)
Net increase (decrease) in cash and cash equivalents	64,990			7,554
Cash and cash equivalents at beginning of period	$	77,459		$	69,905
Cash and cash equivalents at end of period	$	142,449		$	77,459
Supplemental disclosure
Income taxes paid	$	35,939		$	29,296
Change in Capital expenditure accrual	$	(13	)	$	(79	)

The accompanying notes are an integral part of these financial statements.

5

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

1. Organization and Nature of Business

Alba Plant LLC (the “Company”) is an exempted limited liability company organized under the laws of the Cayman Islands. The purposes of the Company are (i) to construct, own, operate and maintain the Alba Liquefied Petroleum Gas Plant (“the plant”); (ii) to further process the natural gas produced under the Alba Production Sharing Contract (“Alba PSC”); (iii) to recover additional condensate; (iv) to separate butane and propane from the natural gas and process them into gas liquids; (v) to store the liquid hydrocarbons processed; (vi) to sell all liquid hydrocarbons produced by the plant; and (vii) to finance such activities on terms the Company determines to be appropriate. The Company commenced commercial operations in January 1997. Sociedad Nacional de Gas de Guinea Ecuatorial (“Sonagas”) has a 20% ownership in the Company with the remaining 80% owned by Alba Associates LLC. The ownership interest in Alba Associates LLC is as follows as of December 31, 2017 and 2016:

Samedan of North Africa, LLC ("Samedan")	34.79166%
Marathon E.G. LPG Limited ("EG LPG")	23.45834
Marathon E.G. Alba Limited ("EG Alba")	19.08334
Marathon E.G. Production Limited ("MEGPL")	11.45833
Marathon E.G. Offshore Limited ("EG Offshore")	11.20833
	100.00000%

The Equatorial Guinea Government is entitled to a 10% interest in the Company’s annual net profit, as defined in the Processing and Marketing Agreement (“PMA”) between The Republic of Equatorial Guinea and the Company dated January 22, 1996.

The Company has no employees, and as such has entered into an agreement with MEGPL to provide certain operating, general and administrative services on behalf of the Company (Note 6).

2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expenses during the respective reporting periods. Actual results could differ from those estimates.

Foreign Currency Transactions

The functional currency applicable to the Company is the U.S dollar. Current assets and current liabilities denominated in other currencies are converted into U.S. Dollars at the applicable rate on the balance sheet date, and the resulting unrealized foreign exchange gains and losses are recorded in the statement of income.

Cash and Cash Equivalents

Includes cash on hand and highly liquid investments with original maturities of three months or less.

6

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

Receivables less Allowance for Doubtful Accounts

Receivables recorded in the financial statements represent bona fide claims against debtors, or other charges arising on or before the balance sheet date. All receivables have been appropriately reduced to their estimated net realizable value. All receivables are recorded at the invoiced amounts and do not bear interest. An allowance for receivables is created with a charge directly to bad debt expense when it becomes probable the receivables will not be collected. No allowance has been recorded as of December 31, 2017 and December 31, 2016.

Inventory

Materials and supplies inventory is valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate. Condensate, propane, and butane inventories are recorded at weighted average cost and carried at the lower of cost or net realizable value.

Facility Cost

Facility cost represents the cost of the plant including related extraction components, piping and other equipment, and includes the cost of related engineering and design services and installation materials and labor. Facility costs are primarily depreciated on a straight-line basis. In 2016, the anticipated commercial life of the Alba PSC was extended as a result of the installation of a new compression platform. Accordingly, the Company extended the estimated remaining life of the plant for depreciation purposes from 2026 to 2034.

Maintenance and repairs are charged to expense as incurred. Renewals, betterments and major repairs that materially extend the life of the plant are capitalized.

We evaluate the plant including related extraction components, piping and other equipment, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. If the value from the use of the asset and its eventual disposition is anticipated to be less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Assets deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value.

Under the provisions of the PMA, the Company is not legally obligated to dismantle the plant and restore the Alba site, and as such, no asset retirement obligation has been recorded for these facilities.

Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include the Company’s expectation to generate sufficient future taxable income including tax credits, and operating loss carryforwards. Valuation allowances are recorded against a deferred tax asset when it is more likely than not that the deferred tax asset will not be realized. We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.

Revenue Recognition

Revenues are recognized when title is transferred to customers, the sales price is fixed or determinable, and collectability is reasonably assured. Costs associated with revenues are recorded in direct operating costs.

7

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

Concentration of Credit Risk

During 2017 and 2016 substantially all of the LPG products were sold to an individual third-party purchaser. Additionally, all of the condensate was sold to a related party. This concentration of customers may impact the Company’s credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

3. Accounting Standards

Not Yet Adopted

In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in 2019, however early adoption is permitted. Upon adoption the standard shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). We plan to adopt this new standard using the modified retrospective method. We continue to assess our contracts that will be subject to this standard and the impact it will have on our results of operations, financial position or cash flows. We plan to provide the disclosures required by this standard, such as key sources of revenues from transactions with customers, disaggregated revenue information, and significant accounting estimates and judgments, upon adoption.

In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. We will adopt this standard in 2018 on a retrospective basis with no significant impact on our results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in 2020 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our results of operations, financial position or cash flows.

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our results of operations, financial position or cash flows.

Recently Adopted

In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using the last-in first-out (“LIFO”) method or the retail inventory method. This standard was effective for us in 2017, and was applied prospectively. Adoption of this standard did not have a significant impact on our results of operations, financial position or cash flows.

8

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

4. Inventory

Inventory as of December 31, 2017 and 2016 is summarized as follows:

(in thousands of dollars)	2017		2016
Materials and supplies	$	37,074	$	36,381
Liquid hydrocarbon products	619		656
	$	37,693	$	37,037

5. Income Taxes

For income tax purposes, Alba Plant LLC is treated as a local corporation and is only subject to local income taxes in accordance with the PMA between The Republic of Equatorial Guinea and Alba Plant LLC dated January 22, 1996. The Company’s effective tax rate for 2017 and 2016 was 25%. Income before income taxes for Alba Plant LLC was $324,468 and $166,615 for 2017 and 2016 respectively.

The provision for income tax expense comprises:

(in thousands of dollars)	2017		2016
Current tax expense	$	74,325	$	35,914
Deferred tax expense	6,827		5,723
	$	81,152	$	41,637

The deferred tax assets and deferred tax liability resulted from the following:

(in thousands of dollars)	2017		2016
Deferred tax assets
Government royalty - net profit interest	$	7,094	$	4,384
	$	7,094	$	4,384
Deferred tax liability
Facility cost	$	53,939	$	44,402
	$	53,939	$	44,402
Net deferred tax liabilities	$	46,845	$	40,018

As of December 31, 2017 our income tax returns for Equatorial Guinea remain subject to examination for the tax years 2007-2016. As of December 31, 2017 and 2016 there are no uncertain tax positions.

9

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

6. Related Party Transactions

Related parties include:

• Alba Associates LLC and Sonagas, the Company’s owners;

• Samedan, EG LPG, EG Alba, MEGPL, and EG Offshore, the owners in Alba Associates LLC; and

• Marathon Oil Marketing, Ltd. (“MOM”), Marathon International Oil (G.B.) Limited (“MIOGB”), Equatorial Guinea LNG Train1, S.A. (“EG LNG”) and other affiliates of Marathon Oil Corporation (“Marathon”), which is one of the ultimate owners of Alba Associates LLC.

The Company enters into certain sales and purchases and has certain accounts receivable and accounts payable with related parties arising in the normal course of business. Accounts receivable, less allowance for doubtful accounts and accounts payable associated with related parties at December 31, 2017 and 2016, consist of the following:

	2017				2016
(in thousands of dollars)	Receivable from		Payable to		Receivable from		Payable to
Sonagas	$	1,538	$	—	$	681	$	—
MOM	13,174		10		10,126		—
MIOGB	—		4		—		—
MEGPL	17		7,026		18		6,979
Marathon	2		13		—		12
EG LNG	—		—		33		—
	$	14,731	$	7,053	$	10,858	$	6,991

Plant products-related parties revenue for the years ended December 31, 2017 and 2016, relate to LPG sold to Sonagas, and propane sold to EG LNG.

Condensate-related parties revenue for the years ended December 31, 2017 and 2016, relates to sales of condensate to MIOSCO (GB) and MOM (beginning in October 2016).

Other income-related parties for the years ended December 31, 2017 and 2016, relates to terminal fees on condensate sold to MIOSCO (GB) and MOM (beginning in October 2016).

The Company purchases its feed gas from gas produced under the Alba PSC at a rate of $0.25/mmbtu as specified in the PMA. MEGPL, the operator of Alba PSC, collects the funds related to the feed gas sales.

Direct operating expenses-related parties for the years ended December 31, 2017 and 2016, were costs incurred by MEGPL for the operation of the plant and billed to the Company in accordance with the Technical and Administrative Services Agreement. This agreement is effective through 120 days after processing activities have terminated, as defined by the agreement. Additionally, the Company has agreed to pay an overhead fee to MEGPL equal to 1% of all cost incurred in support of plant operations.

10

Alba Plant LLC

Notes to Financial Statements

December 31, 2017 and 2016

Shipping and handling services, and general and administrative services are provided primarily by MEGPL. These services are charged to the Company at cost.

7. Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables and short-term payables. The carrying amounts approximate fair market value due to the highly liquid nature of the short-term instruments.

8. Dividends

In accordance with the Alba Plant Members’ Agreement, all available funds, as defined in the agreement, are distributed to the Company’s owners on the basis of their respective ownership. Dividends distributed in 2017 and 2016 were $242 million and $142 million, respectively. Dividends per share in 2017 and 2016 were $242 thousand and $142 thousand respectively.

9. Contingencies

Various local laws and regulations affect the Company’s operations and costs. Management believes that the Company is in substantial compliance with all applicable local laws and regulations and that the ultimate resolution of any claims or legal proceedings, if any, instituted against the Company will not have a material effect on its financial position, results of operations, or cash flows.

10. Subsequent Events

In February 2018, the Company obtained approval and distributed $56 million to its shareholders. Events and transactions subsequent to the balance sheet date have been evaluated through February 22, 2018, the date these financial statements were issued, for potential recognition or disclosure in the financial statements.

11

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 15, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Period Focus	Q4
Document Fiscal Year Focus	2017
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corp
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		849,755,866
Entity Public Float			$ 10,050

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues and other income:
Sales and other operating revenues, including related party	$ 4,211	$ 2,930	$ 4,136
Marketing revenues	162	240	499
Income from equity method investments	256	175	145
Net gain (loss) on disposal of assets	58	389	120
Other income	78	53	53
Total revenues and other income	4,765	3,787	4,953
Costs and expenses:
Production	706	712	979
Marketing, including purchases from related parties	168	245	500
Other operating	431	484	410
Exploration	409	323	971
Depreciation, depletion and amortization	2,372	2,156	2,721
Impairments	229	67	721
Taxes other than income	183	151	216
General and administrative	400	481	588
Total costs and expenses	4,898	4,619	7,106
Income from operations	(133)	(832)	(2,153)
Net interest and other	(270)	(332)	(286)
Gain (Loss) on Extinguishment of Debt	(51)	0	0
Income from continuing operations before income taxes	(454)	(1,164)	(2,439)
Provision for income taxes	376	923	(738)
Income from continuing operations	(830)	(2,087)	(1,701)
Discontinued operations	(4,893)	(53)	(503)
Net income (loss)	$ (5,723)	$ (2,140)	$ (2,204)
Basic:
Income from continuing operations (in dollars per basic share)	$ (0.97)	$ (2.55)	$ (2.51)
Discontinued operations (in dollars per basic share)	(5.76)	(0.06)	(0.75)
Net income (in dollars per basic share)	(6.73)	(2.61)	(3.26)
Diluted:
Income from continuing operations (in dollars per diluted share)	(0.97)	(2.55)	(2.51)
Discontinued operations (in dollars per diluted share)	(5.76)	(0.06)	(0.75)
Net income (in dollars per diluted share)	(6.73)	(2.61)	(3.26)
Dividends (in dollars per share)	$ 0.2	$ 0.20	$ 0.68
Weighted average shares:
Basic	850	819	677
Diluted	850	819	677

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (5,723)	$ (2,140)	$ (2,204)
Postretirement and postemployment plans
Change in actuarial loss and other	21	16	228
Income tax benefit (provision) on postretirement and postemployment plans	7	(4)	(86)
Postretirement and postemployment plans, net of tax	28	12	142
Derivative hedges
Net unrecognized gain (loss)	(13)	61	0
Reclassification of gains on terminated derivative hedges	(47)	0	0
Income tax provision on derivative hedges	21	(22)	0
Derivative hedges, net of tax	(39)	39	0
Net recognized loss reclassified to discontinued operations	34	0	0
Income tax provision (benefit)	(4)	0	0
Foreign currency hedges, net of tax	30	0	0
Other, net of tax	2	1	0
Other comprehensive income (loss)	21	52	142
Comprehensive income (loss)	$ (5,702)	$ (2,088)	$ (2,062)

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 563	$ 2,488
Receivables, less reserve of $12 and $6	1,082	748
Notes, Loans and Financing Receivable, Net, Current	748	0
Inventories	126	136
Other current assets	36	66
Disposal Group, Including Discontinued Operation, Assets, Current	11	227
Total current assets	2,566	3,665
Equity method investments	847	931
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,564 and $20,255	17,665	16,727
Goodwill	115	115
Other noncurrent assets	764	558
Noncurrent assets held for sale	55	9,098
Total assets	22,012	31,094
Current liabilities:
Accounts payable	1,395	967
Payroll and benefits payable	108	129
Accrued taxes	177	94
Other current liabilities	288	243
Long-term debt due within one year	0	686
Disposal Group, Including Discontinued Operation, Liabilities, Current	0	121
Total current liabilities	1,968	2,240
Long-term debt	5,494	6,581
Deferred tax liabilities	833	769
Defined benefit postretirement plan obligations	362	345
Asset retirement obligations	1,428	1,602
Deferred credit and other liabilities	217	225
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	2	1,791
Total liabilities	10,304	13,553
Commitments and contingencies
Stockholders’ Equity
Preferred stock no shares issued or outstanding (no par value, 26 million shares authorized)	0	0
Common stock issued - 937 million and 937 million shares (par value $1 per share, 1.1 billion shares authorized)	937	937
Common stock, held in treasury, at cost – 87 million and 90 million shares	(3,325)	(3,431)
Additional paid-in capital	7,379	7,446
Retained earnings	6,779	12,672
Accumulated other comprehensive loss	(62)	(83)
Total stockholders equity	11,708	17,541
Total liabilities and stockholders equity	$ 22,012	$ 31,094

XML

Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets Parenthetical [Abstract]
Allowance for doubtful accounts	$ 12	$ 6
Less accumulated depreciation, depletion and amortization	$ (21,564)	$ (20,255)
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	26,000,000	26,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock, shares authorized	1,100,000,000	1,100,000,000
Common stock, shares issued	937,000,000	937,000,000
Held in treasury, shares	87,000,000	90,000,000

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Cash Flows [Abstract]
Net income (loss)	$ (5,723)	$ (2,140)	$ (2,204)
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	4,893	53	503
Depreciation, depletion and amortization	2,372	2,156	2,721
Impairments	229	67	721
Exploratory dry well costs and unproved property impairments	323	220	867
Net (gain) loss on disposal of assets	(58)	(389)	(120)
Deferred income taxes	(61)	828	(804)
Gain (Loss) on Sale of Derivatives	(11)	63	(126)
Net cash received (paid) in settlement of derivative instruments	98	61	55
Share-based Compensation	50	48	45
Equity method investments, net	20	17	33
Changes in:
Current receivables	(334)	67	790
Inventories	10	64	25
Current accounts payable and accrued liabilities	297	(137)	(906)
All other operating, net	(117)	(77)	(63)
Net cash provided by continuing operations	1,988	901	1,537
Investing activities:
Additions to property, plant and equipment	(1,974)	(1,204)	(3,485)
Acquisitions, net of cash acquired	(1,891)	(902)	0
Disposal of assets	1,787	1,219	225
Investments - return of capital	64	55	77
Payments to Acquire Investments	0	0	(925)
Proceeds from Sale, Maturity and Collection of Investments	0	0	925
All other investing, net	(30)	(1)	24
Net cash used in investing activities	(2,044)	(833)	(3,159)
Financing activities:
Borrowings	988	0	1,996
Debt repayments	(2,764)	(1)	(1,069)
Payment for Debt Extinguishment or Debt Prepayment Cost	(46)	0	0
Proceeds from Issuance of Common Stock	0	1,236	0
Purchases of common stock	(11)	(6)	(11)
Dividends paid	(170)	(162)	(460)
All other financing, net	0	1	(5)
Net cash provided by (used in) financing activities	(2,003)	1,068	451
Cash Provided by (Used in) Operating Activities, Discontinued Operations	141	177	39
Investing activities of discontinued operations	(13)	(41)	(43)
Change in cash included in current assets held for sale	2	100	90
Net cash provided by discontinued operations	130	236	86
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	4	(3)	(3)
Net increase (decrease) in cash and cash equivalents	(1,925)	1,369	(1,088)
Cash and cash equivalents at beginning of period	2,488	1,119	2,207
Cash and cash equivalents at end of period	$ 563	$ 2,488	$ 1,119

XML

Consolidated Statements of Stockholders Equity - USD ($) shares in Millions, $ in Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Treasury shares				95
Beginning Balance at Dec. 31, 2014	$ 21,020	$ 0	$ 770	$ (3,642)	$ 6,531	$ 17,638	$ (277)
Shares Beginning Balance at Dec. 31, 2014			770
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock based compensation	64			96	(32)
Shares repurchased	(8)			$ (8)
Stock-based compensation	(1)				(1)
Net loss	(2,204)					(2,204)
Other Comprehensive Income (Loss), Net of Tax, Incl Disc Ops	142						142
Dividends paid	(460)					(460)
Shares issued - stock based compensation				(2)
Shares repurchased				0
Ending Balance at Dec. 31, 2015	18,553	0	$ 770	$ (3,554)	6,498	14,974	(135)
Shares Ending Balance at Dec. 31, 2015			770
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Treasury shares				93
Shares issued - stock based compensation	42			$ 128	(86)
Shares repurchased	(5)			$ (5)
Stock-based compensation	(35)				(35)
Net loss	(2,140)					(2,140)
Other Comprehensive Income (Loss), Net of Tax, Incl Disc Ops	52						52
Dividends paid	(162)					(162)
Common stock issuance	1,236		$ 167		1,069
Shares issued - stock based compensation				(3)
Shares repurchased				0
Stock Issued During Period, Shares, New Issues			167
Ending Balance at Dec. 31, 2016	$ 17,541	0	$ 937	$ (3,431)	7,446	12,672	(83)
Shares Ending Balance at Dec. 31, 2016			937
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Treasury shares	90			90
Shares issued - stock based compensation	$ 67			$ 117	(50)
Shares repurchased	(11)			$ (11)
Stock-based compensation	(17)				(17)
Net loss	(5,723)					(5,723)
Other Comprehensive Income (Loss), Net of Tax, Incl Disc Ops	21						21
Dividends paid	(170)					(170)
Common stock issuance	0
Shares issued - stock based compensation				(3)
Shares repurchased				0
Ending Balance at Dec. 31, 2017	$ 11,708	$ 0	$ 937	$ (3,325)	$ 7,379	$ 6,779	$ (62)
Shares Ending Balance at Dec. 31, 2017			937
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Treasury shares	87			87

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Summary of Principal Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Principal Accounting Policies

Summary of Principal Accounting Policies

We are a global energy company engaged in exploration, production and marketing of crude oil and condensate, NGLs and natural gas; as well as production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.

Basis of presentation and principles applied in consolidation – These consolidated financial statements include the accounts of our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments– Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Reclassifications – We have reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.

Discontinued operations – As a result of the sale of our Canadian business in 2017, we reflected this business as discontinued operations in all periods presented. Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Assets and liabilities are presented as held for sale in the historical periods in the consolidated balance sheets. See Note 5 for discussion of the divestiture in further detail.

As discussed above we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases in the second quarter 2017. The characteristics and composition of our North America E&P reporting segment remained unchanged and there was no effect on previously reported segment information. As all our remaining properties within the segment are located within the United States, we concluded that our North America E&P segment would be renamed United States E&P segment, effective June 30, 2017. During the year, no changes occurred to our International E&P segment. See Note 6 for further information on our reportable segments.

Use of estimates – The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Estimated quantities of crude oil and condensate, NGLs and natural gas reserves is a significant estimate that requires judgment. All of the reserve data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and condensate, NGLs and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and condensate, NGLs and natural gas that are ultimately recovered. See Supplementary Data - Supplementary Information on Oil and gas Producing Activities for further detail.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, asset retirement obligations, goodwill, valuation of derivative instruments and valuation allowances for deferred income tax assets, among others. Although we believe these estimates are reasonable, actual results could differ from these estimates.

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of crude oil and condensate, NGLs and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Short-term Investments - Our short-term investments are comprised of bank time deposits with original maturities of greater than three months but less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost.

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. We routinely assess the collectability of receivable balances to determine if the amount of the reserve in allowance for doubtful accounts is sufficient.

Notes receivable - We hold two notes receivable from the sale of our Canadian business, which closed in the second quarter of 2017. Both notes receivable were initially recorded at fair value and are reported at amortized cost. The notes receivable are evaluated for collectability on an individual basis each reporting period, based on the financial condition of the debtor. No allowances for credit losses were established for the notes receivable as of December 31, 2017. See Note 5 for additional discussion.

Inventories – Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, commodity locational risk, foreign currency risk and interest rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities. Our derivative instruments contain no significant contingent credit features.

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Cash flow hedges – We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. Derivative instruments designated as cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The effective portion of changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged item is reclassified to net income when the underlying forecasted transaction is recognized in net income. Ineffective portions of a cash flow hedge’s change in fair value are recognized currently within net interest and other on the consolidated statements of income. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in other comprehensive income is immediately reclassified into net income.

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price and locational risks on the forecasted sale of crude oil and natural gas that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. If significant transfers occur, they would be disclosed in Note 14 to the consolidated financial statements.

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities.

Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells in progress and those that find proved reserves, and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities, as well as property, plant and equipment unrelated to oil and gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets as summarized below.

Type of Asset	Range of Useful Lives
Office furniture, equipment and computer hardware	4 to 15 years
Pipelines	10 to 40 years
Plants, facilities and infrastructure	3 to 40 years

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income.

Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reflected in net gain (loss) on disposal of assets in our consolidated statements of income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized either when the assets are classified as held for sale, or are measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model depending on timing of the sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to a reporting unit. The fair value of a reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs – We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable. Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production facilities and equipment, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis based on estimated proved developed reserves for oil and gas production facilities, while accretion of the liability occurs over the useful lives of the assets.

Deferred income taxes – Deferred tax assets and liabilities, measured at enacted tax rates, are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include whether we are in a cumulative loss position in recent years, our reversal of temporary differences, and our expectation to generate sufficient future taxable income. We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected volatility of our stock price and the stock price in relation to the strike price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employees' behalf are presented within the financing activities section instead of the operating activities section of the statement of cash flows. We elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for the years ended December 31, 2016 or 2015. Excess tax benefits were classified as an operating activity within the statement of cash flows on a prospective basis beginning in 2017; as such, prior periods were not adjusted. See Note 2 for additional discussion.

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Accounting Standards

12 Months Ended

Dec. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Standards

Accounting Standards

Not Yet Adopted

In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method. The adoption of this ASU will not have a material impact on our consolidated results of operations, financial position or cash flows. However, as a result of this standard we will change our presentation of marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the years ended December 31, 2017 and 2016, we expect the impact of this change to be a reduction of approximately $130 million and $100 million, respectively, in marketing revenue and expenses in our consolidated results of operations. We will provide the disclosures required by this standard, such as key sources of revenues from transactions with customers, disaggregated revenue information, and significant accounting estimates and judgments, beginning in the first quarter of 2018.

In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. We will adopt this standard in the first quarter of 2018 on a retrospective basis, and will reclassify certain amounts from general and administrative expense to the exploration, production and our new other net periodic benefit costs expense categories on our consolidated statements of income.

In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. We will adopt this standard during the first quarter of 2018 on a retrospective basis with no significant impact on our consolidated results of operations, financial position or cash flows.

In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. We will adopt this standard in the first quarter of 2018 on a retrospective basis and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. We will adopt this standard in the first quarter of 2018 using the modified retrospective approach with no material impact on our consolidated results of operations, financial position or cash flows.

In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. We will adopt this standard in the first quarter of 2018 on a prospective basis. Since we adopted the standard on a prospective basis, adoption of this standard will not have a significant impact on our consolidated results of operations, financial position or cash flows for prior periods.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. We plan to adopt this standard in the first quarter of 2018 and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our consolidated results of operations, financial position or cash flows.

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this accounting standards update, including transition requirements, and are assessing the impact it may have on our results of operations, financial position, or cash flows.

In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Accounting Standards

Not Yet Adopted

In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method. The adoption of this ASU will not have a material impact on our consolidated results of operations, financial position or cash flows. However, as a result of this standard we will change our presentation of marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the years ended December 31, 2017 and 2016, we expect the impact of this change to be a reduction of approximately $130 million and $100 million, respectively, in marketing revenue and expenses in our consolidated results of operations. We will provide the disclosures required by this standard, such as key sources of revenues from transactions with customers, disaggregated revenue information, and significant accounting estimates and judgments, beginning in the first quarter of 2018.

In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. We will adopt this standard in the first quarter of 2018 on a retrospective basis, and will reclassify certain amounts from general and administrative expense to the exploration, production and our new other net periodic benefit costs expense categories on our consolidated statements of income.

In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. We will adopt this standard during the first quarter of 2018 on a retrospective basis with no significant impact on our consolidated results of operations, financial position or cash flows.

In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. We will adopt this standard in the first quarter of 2018 on a retrospective basis and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. We will adopt this standard in the first quarter of 2018 using the modified retrospective approach with no material impact on our consolidated results of operations, financial position or cash flows.

In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. We will adopt this standard in the first quarter of 2018 on a prospective basis. Since we adopted the standard on a prospective basis, adoption of this standard will not have a significant impact on our consolidated results of operations, financial position or cash flows for prior periods.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. We plan to adopt this standard in the first quarter of 2018 and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our consolidated results of operations, financial position or cash flows.

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this accounting standards update, including transition requirements, and are assessing the impact it may have on our results of operations, financial position, or cash flows.

In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

Recently Adopted

In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard was effective for us in the first quarter of 2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our financial statements.

In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in the first quarter of 2017, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

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Income per Common Share

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Income per Common Share

Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below exclude 11 million, 13 million and 13 million stock options in 2017, 2016 and 2015 that were antidilutive.

	Year Ended December 31,
(In millions, except per share data)	2017			2016			2015
Income (loss) from continuing operations	$	(830	)	$	(2,087	)	$	(1,701	)
Income (loss) from discontinued operations	(4,893		)	(53		)	(503		)
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Weighted average common shares outstanding	850			819			677
Per basic share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)
Per diluted share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)

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Acquisitions

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

Acquisitions

2017 - United States E&P

In the fourth quarter of 2017, we closed on our acquisition of additional acreage in the Northern Delaware basin of New Mexico from a private seller for $63 million in cash, subject to post-closing adjustments. We accounted for this transaction as an asset acquisition, allocating the purchase price to unproved property within property, plant and equipment.

In the second quarter of 2017, we closed on our acquisitions of approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin of New Mexico. On May 1, 2017, we closed on our acquisition with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately 70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017, we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment.

2016 - United States E&P

On August 1, 2016, we closed on our acquisition of PayRock Energy Holdings, LLC (“PayRock”), a portfolio company of EnCap Investments, including approximately 61,000 net surface acres in the oil window of the Anadarko Basin STACK play in Oklahoma. The purchase price of $904 million, subject to closing adjustments, was paid with cash on hand. We accounted for this transaction as an asset acquisition, with a majority of the purchase price allocated to unproved property within property, plant and equipment.

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Dispositions

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

Dispositions

Oil Sands Mining Segment

On May 31, 2017 we closed on the sale of our Canadian business, which included our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million. We recorded these notes receivable at fair value, see Note 14 for fair value measurements. Our notes receivable are with 10084751 Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant and equipment of our Canadian business. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business that were recorded in our financial statements but transferred to the buyer upon closing.

Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our consolidated statements of income as discontinued operations:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total sales and other revenues and other income	$	431		$	863		$	908
Net gain (loss) on disposal of assets	(43		)	—			—
Total revenues and other income	388			863			908
Costs and expenses:
Production expenses	254			601			715
Exploration expenses	—			7			347
Depreciation, depletion and amortization	40			239			236
Impairments	6,636			—			31
Other	25			87			98
Total costs and expenses	6,955			934			1,427
Pretax income (loss) from discontinued operations	(6,567		)	(71		)	(519		)
Provision (benefit) for income taxes	(1,674		)	(18		)	(16		)
Income (loss) from discontinued operations	$	(4,893	)	$	(53	)	$	(503	)

The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and other non-core international assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at December 31, 2017 and December 31, 2016:

	December 31,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	—	$	2
Accounts receivables	—		129
Inventories	—		91
Other	—		4
Total current assets held for sale—discontinued operations	—		226
Total current assets held for sale—continuing operations	11		1
Total current assets held for sale	$	11	$	227
Noncurrent assets:
Property, plant and equipment, net	$	—	$	8,991
Other	—		106
Total noncurrent assets held for sale—discontinued operations	—		9,097
Total noncurrent assets held for sale—continuing operations	55		1
Total noncurrent assets held for sale	$	55	$	9,098
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	111
Other	—		10
Total current liabilities held for sale—discontinued operations	—		121
Total current liabilities held for sale—continuing operations	—		—
Total current liabilities held for sale	$	—	$	121
Noncurrent liabilities:
Asset retirement obligations	$	—	$	95
Deferred tax liabilities	—		1,669
Other	—		20
Total noncurrent liabilities held for sale—discontinued operations	—		1,784
Total noncurrent liabilities held for sale—continuing operations	2		7
Total noncurrent liabilities held for sale	$	2	$	1,791

United States E&P Segment

As disclosed above, we closed on the sale of our Canadian business in May of 2017. This sale included interests in our exploration stage in-situ leases which were included within our historically named North America E&P Segment. See Note 6 for further detail on our segments. These interests have been reflected as discontinued operations and are included within the disclosure above.

In July 2017, we entered into an agreement to sell certain conventional assets in Oklahoma. We closed on the sale in September 2017 for proceeds of $25 million, and recognized a pre-tax gain of $21 million.

In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas and New Mexico. The sale closed in late October for proceeds of $235 million, and we recognized a total pre-tax gain of $63 million. During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to multiple purchasers for combined proceeds of approximately $67 million, and recognized a total pre-tax gain of $55 million.

In April 2016, we announced the sale of our Wyoming upstream and midstream assets. During the second quarter, we received proceeds of approximately $690 million and recorded a pre-tax gain of $266 million with the remaining asset sales closing in November 2016 for proceeds of $155 million, excluding closing adjustments. A pre-tax gain of $38 million was recognized in the fourth quarter 2016.

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds. We closed on certain of the asset sales and recognized a net pre-tax loss on sale of $48 million in 2016, the remaining asset closed in 2017 with a net pre-tax gain on sale of $32 million.

In November 2015, we entered into an agreement to sell our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius and Neptune fields in the Gulf of Mexico. The transaction closed in December 2015, excluding the Neptune field, for proceeds of $111 million. A $228 million pretax gain was recorded in the fourth quarter of 2015. The Neptune field transaction closed during the first quarter of 2016 for cash proceeds of $4 million.

In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (see Note 14).

International E&P Segment

In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the second half of 2017 and recognized no net pre-tax gain or loss on sale. The remaining asset sale is expected to close during 2018 and is classified as held for sale in the consolidated balance sheet as of December 31, 2017, with total assets of $66 million and total liabilities of $2 million. See Note 10 for further detail on impairment expenses recognized concurrently with these agreements.

In the third quarter of 2015, we entered into agreements to sell our East Africa exploration acreage in Ethiopia and Kenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction closed during the first quarter of 2016.

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Segment Information

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segment Information

Segment Information

We have two reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• United States E&P ("U.S. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

• International E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income (loss) represents income (loss) which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, changes in our valuation allowance, unrealized gains or losses on derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

As discussed in Note 5, we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases, in the second quarter of 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented. Additionally, we renamed our North America E&P segment to United States E&P segment effective June 30, 2017 in all periods presented. See Note 1 for further information.

Year Ended December 31, 2017						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,138		$	1,154	$	(81	)	(b)	$	4,211
Marketing revenues	29			133		—				162
Total revenues	3,167			1,287		(81		)		4,373
Income from equity method investments	—			256		—				256
Net gain on disposal of assets and other income	13			6		117			(c)	136
Less:
Production expenses	476			229		1				706
Marketing costs	36			132		—				168
Other operating	354			77		—				431
Exploration	154			5		250			(d)	409
Depreciation, depletion and amortization	2,011			328		33				2,372
Impairments	4			—		225			(e)	229
Taxes other than income	173			—		10				183
General and administrative	119			32		249			(f)	400
Net interest and other	—			—		270			(g)	270
Loss on early extinguishment of debt	—			—		51			(h)	51
Income tax provision (benefit)	1			372		3				376
Segment income (loss) / Income (loss) from continuing operations	$	(148	)	$	374	$	(1,056	)		$	(830	)
Capital expenditures (a)	$	2,081		$	42	$	27			$	2,150

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to sale of certain conventional assets in Oklahoma and Colorado. (See Note 5).

^(d) Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(e)  Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(f)   Includes pension settlement loss of $32 million (see Note 17).

^(g) Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 13.)

^(h) Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 15.)

Year Ended December 31, 2016						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	2,375		$	665	$	(110	)	(b)	$	2,930
Marketing revenues	135			105		—				240
Total revenues	2,510			770		(110		)		3,170
Income (loss) from equity method investments	—			175		—				175
Net gain on disposal of assets and other income	28			32		382			(c)	442
Less:
Production expenses	486			226		—				712
Marketing costs	142			103		—				245
Other operating	328			43		113			(d)	484
Exploration	127			17		179			(e)	323
Depreciation, depletion and amortization	1,835			276		45				2,156
Impairments	20			—		47			(f)	67
Taxes other than income	149			—		2				151
General and administrative	94			35		352			(g)	481
Net interest and other	—			—		332				332
Income tax provision (benefit)	(228		)	49		1,102			(h)	923
Segment income (loss) / Income (loss) from continuing operations	$	(415	)	$	228	$	(1,900	)		$	(2,087	)
Capital expenditures (a)	$	936		$	82	$	18			$	1,036

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to net gain on disposal of assets(see Note 5).

^(d)  Includes termination payment on our Gulf of Mexico deepwater drilling rig commitment of $113 million.

^(e) Primarily related to impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (See Note 10).

^(f)  Proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $103 million and severance related expenses associated with workforce reductions of $8 million (see Note 17).

^(h)  Increased valuation allowance on certain of our deferred tax assets $1,346 million (see Note 7).

Year Ended December 31, 2015						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,358		$	728	$	50		(b)	$	4,136
Marketing revenues	396			103		—				499
Total revenues	3,754			831		50				4,635
Income from equity method investments	—			157		(12		)	(c)	145
Net gain on disposal of assets and other income	24			27		122			(d)	173
Less:
Production expenses	724			255		—				979
Marketing costs	401			99		—				500
Other operating	335			48		27				410
Exploration	314			101		556			(e)	971
Depreciation, depletion and amortization	2,377			295		49				2,721
Impairments	2			—		719			(f)	721
Taxes other than income	215			—		1				216
General and administrative	127			44		417			(g)	588
Net interest and other	—			—		286				286
Income tax provision (benefit)	(265		)	61		(534		)		(738		)
Segment income (loss) / Income (loss) from continuing operations	$	(452	)	$	112	$	(1,361	)		$	(1,701	)
Capital expenditures (a)	$	2,553		$	368	$	25			$	2,946

^(a)  Includes accruals.

^(b)  Unrealized gain on commodity derivative instruments.

^(c)  Partial impairment of investment in equity method investee (See Note 14).

^(d)  Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage(see Note 5).

^(e) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 10).

^(f)  Includes goodwill impairment (see Note 12) and proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $119 million (see Note 17) and severance related expenses associated with workforce reductions of $55 million.

Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.

	Year Ended December 31,
(In millions)	2017		2016		2015
United States	$	3,086	$	2,400	$	3,804
Equatorial Guinea	530		444		444
Libya	431		54		—
U.K.	289		263		380
Other international	37		9		7
Total revenues	$	4,373	$	3,170	$	4,635

In 2017, sales to Vitol and each of their respective affiliates accounted for approximately 10% of our total revenues. In 2016, sales to Valero Marketing and Supply, Tesoro Petroleum, and Flint Hills Resources and each of their respective affiliates accounted for approximately 13%, 11% and 10% of our total revenues. In 2015, sales to Shell Oil and its affiliates accounted for approximately 10% of our total revenues.

The following summarizes revenues by product line.

	Year Ended December 31,
(In millions)	2017		2016		2015
Crude oil and condensate	$	3,477	$	2,605	$	3,963
Natural gas liquids	338		198		203
Natural gas	510		356		464
Other	48		11		5
Total revenues	$	4,373	$	3,170	$	4,635

The following summarizes property, plant and equipment and equity method investments.

	December 31,
(In millions)	2017		2016
United States	$	15,971	$	14,272
Equatorial Guinea	1,582		1,794
Other international	959		1,592
Total long-lived assets	$	18,512	$	17,658

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income (loss) before tax expense for continuing operations was:

	Year Ended December 31,
(In millions)		2017			2016			2015
United States		$	(783	)	$	(1,449	)	$	(2,384	)
Foreign		329			285			(55		)
Total		$	(454	)	$	(1,164	)	$	(2,439	)

Income tax provisions (benefits) for continuing operations were:

	Year Ended December 31,
	2017									2016							2015
(In millions)	Current			Deferred			Total			Current		Deferred			Total		Current			Deferred			Total
Federal	$	(32	)	$	41		$	9		$	2	$	836		$	838	$	(41	)	$	(684	)	$	(725	)
State and local	(14		)	2			(12		)	2		8			10		(8		)	(18		)	(26		)
Foreign	483			(104		)	379			91		(16		)	75		115			(102		)	13
Total	$	437		$	(61	)	$	376		$	95	$	828		$	923	$	66		$	(804	)	$	(738	)

A reconciliation of the federal statutory income tax rate applied to income (loss) from continuing operations before income taxes to the provision (benefit) for income taxes follows:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total pre-tax income (loss) from continuing operations	$	(454	)	$	(1,164	)	$	(2,439	)
Total income tax expense (benefit)	$	376		$	923		$	(738	)
Effective income tax expense (benefit) rate on continuing operations	83		%	79		%	(30		)%
Income taxes at the statutory tax rate of 35% (a)	$	(159	)	$	(407	)	$	(854	)
Effects of foreign operations	140			47			(55		)
Adjustments to valuation allowances	446			1,270			95
State income taxes	(19		)	9			(15		)
Tax law change	(35		)	6			(3		)
Goodwill impairment	—			—			94
Other federal tax effects	3			(2		)	—
Income tax expense (benefit) on continuing operations	$	376		$	923		$	(738	)

^(a) Includes income tax benefits primarily related to our U.S. federal income taxes where we have maintained a full valuation allowance since December 2016.

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments appears in the "Not Allocated to Segments" column of the tables in Note 6.

Effects of foreign operations – The effects of foreign operations increased our tax expense in 2017, 2016, and 2015 due to the mix of pretax income between high and low tax jurisdictions. This increase primarily relates to increased sales volumes in Libya during 2017 where the tax rate is 93.5%. Excluding Libya, the effective tax rates on continuing operations would be an expense of 5% in 2017, an expense of 79% in 2016, and a benefit of 29% in 2015.

Adjustments to valuation allowances - Since December 31, 2016, we have maintained a full valuation allowance on our net federal deferred tax assets. In 2017, we recorded a $446 million valuation allowance primarily related to current year activity in the U.S. Included within the $446 million is a $41 million out-of-period adjustment as a result of identifying certain deferred tax assets for which the impact should have been recorded to other comprehensive income, but had been recorded to income from continuing operations in 2016.

Change in tax law – On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”). Tax Reform Legislation, which is also commonly referred to as “U.S. tax reform”, significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018, and repeal of the corporate alternative minimum tax (“AMT”), and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. The impact of the remeasurement on our federal deferred tax assets and liabilities was equally offset by an adjustment to our valuation allowance with no material impact to current year earnings. We recorded a net benefit of $35 million, classified as a receivable within other noncurrent assets on the consolidated balance sheet, during the fourth quarter of 2017 related to the repeal of the corporate AMT. Although the $35 million net benefit represents what we believe is a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We do not expect to pay U.S. federal cash taxes on the deemed repatriation due to an accumulated deficit in foreign earnings for tax purposes.

Once we finalize certain tax positions when we file our 2017 federal tax return, we will be able to conclude whether any further adjustments are required to our net tax position as of December 31, 2017. Any adjustments to these provisional amounts will be reported as a component of income tax expense (benefit) in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018.

Deferred tax assets and liabilities resulted from the following:

	Year Ended December 31,
(In millions)	2017			2016
Deferred tax assets:
Employee benefits	$	111		$	228
Operating loss carryforwards	1,030			1,065
Capital loss carryforwards	3			4
Foreign tax credits	611			4,430
Other credit carryforwards	—			35
Investments in subsidiaries and affiliates	174			91
Other	69			86
Subtotal	1,998			5,939
Valuation Allowance	(926		)	(4,301		)
Total deferred tax assets	1,072			1,638
Deferred tax liabilities:
Property, plant and equipment	1,332			3,672
Accrued revenue	81			75
Other	3			(7		)
Total deferred tax liabilities	1,416			3,740
Net deferred tax liabilities	$	344		$	2,102

Foreign Tax Credits - As a result of U.S. tax reform, we have reduced our foreign tax credits at December 31, 2017, which are offset by a corresponding reduction in valuation allowance, by $3,819 million due to the remote likelihood these credits will be utilized before expiration. We have not elected any of our foreign earnings to be permanently reinvested abroad. Additionally due to U.S. tax reform, we do not expect future foreign earnings from operations to be subject to tax in the U.S. The remaining foreign tax credits, which are offset by a valuation allowance, expire in 2022 through 2027.

Operating loss carryforwards - At December 31, 2017, our operating loss carryforwards before valuation allowance includes $898 million from the U.S. that expire in 2035-2037. Foreign operating loss carryforwards include $13 million that begin to expire in 2018. State operating loss carryforwards of $119 million expire in 2018 through 2037.

Valuation allowances – At December 31, 2017, we reflect a valuation allowance in our consolidated balance sheet of $926 million against our net deferred tax assets in various jurisdictions in which we operate. The reduction primarily related to the reduction of foreign tax credits in the U.S. In 2016 and 2015, we increased our valuation allowance by $1,268 million and $99 million respectively.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2017		2016
Assets:
Other noncurrent assets	$	489	$	336
Liabilities:
Noncurrent deferred tax liabilities	833		769
Noncurrent liabilities held for sale	—		1,669
Net deferred tax liabilities	$	344	$	2,102

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been completed through the 2014 tax year, with the exception of 2010-11. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the fourth quarter of 2017. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. See Note 24 for further detail. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.

As of December 31, 2017, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2008-2016
Equatorial Guinea	2007-2016
Libya	2012-2016
United Kingdom	2008-2016

^(a)  Includes federal and state jurisdictions.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2017			2016			2015
Beginning balance	$	66		$	65		$	80
Additions for tax positions of prior years	83			6			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Settlements	(20		)	—			(7		)
Statute of limitations	—			—			(9		)
Ending balance	$	126		$	66		$	65

If the unrecognized tax benefits as of December 31, 2017 were recognized, $10 million would affect our effective income tax rate. As of December 31, 2017, there are $83 million uncertain tax positions for which it is reasonably possible that the amount could significantly change during the next twelve months. If this were to significantly change, we estimate that any revisions to current and deferred tax liabilities would have no cumulative adverse earnings impact on our consolidated results of operations.

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs. In the fourth quarter of 2017, we received an adverse ruling from the U.K. first-tier tax tribunal. As a result of the adverse ruling, in the fourth quarter of 2017 we established an uncertain tax position. We have appealed the ruling, but were required to pay the disputed tax amount and associated interest in order to pursue the appeal. The payment of the disputed tax and interest, approximately $108 million, is not considered a settlement of the tax dispute with the U.K. tax authorities. If we prevail in appeals, we will be refunded the tax and interest paid, however, if we do not prevail no further material cash payments are expected due to the initial payment required to appeal the adverse ruling. See Note 24 for further detail.

Interest and penalties are recorded as part of the tax provision and were $2 million, $1 million and $1 million related to unrecognized tax benefits in 2017, 2016 and 2015. As of December 31, 2017 and 2016, $25 million and $15 million of interest and penalties were accrued related to income taxes.

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Inventories

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Inventories

Inventories

Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

	December 31,
(In millions)	2017		2016
Crude oil and natural gas	$	9	$	6
Supplies and other items	117		130
Inventories	$	126	$	136

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

	December 31,
(In millions)	2017		2016
United States E&P	$	15,867	$	14,158
International E&P	1,710		2,470
Corporate	88		99
Net property, plant and equipment	$	17,665	$	16,727

At December 31, 2017, 2016 and 2015 we had total deferred exploratory well costs as follows:

	December 31,
(In millions)	2017			2016			2015
Amounts capitalized less than one year after completion of drilling	$	263		$	131		$	352
Amounts capitalized greater than one year after completion of drilling	32			118			85
Total deferred exploratory well costs	$	295		$	249		$	437
Number of projects with costs capitalized greater than one year after
completion of drilling	1			3			2
(In millions)	2017			2016			2015
Beginning balance	$	249		$	437		$	573
Additions	212			299			610
Charges to expense (a)	(64		)	(23		)	(111		)
Transfers to development	(102		)	(388		)	(635		)
Dispositions(b)	—			(76		)	—
Ending balance	$	295		$	249		$	437

^(a)  Includes $64 million in exploratory well costs being expensed as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon in August of 2017. See Note 10 for further detail.

^(b)  Includes sale of GOM assets in 2016.

Exploratory well costs capitalized greater than one year after completion of drilling are associated with one project in E.G. with costs of $32 million as of December 31, 2017. Management believes this project with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development based on current plans. For this project in E.G., drilling was completed on the Rodo well in Alba Block Sub Area B, offshore E. G. in the first quarter of 2015, and we have since completed a seismic feasibility study. In 2017, we received approval for and proceeded to perform a seismic reprocessing program. After completion of this program we will evaluate drilling opportunities within Sub Area B.

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Impairment and Exploration Expenses (Notes)

12 Months Ended

Dec. 31, 2017

Impairments and Exploration Expenses [Abstract]

Impairments and Exploration Expenses [Text Block]

Impairments and Exploration Expenses

Impairments

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment in our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented

The following table summarizes impairment charges of proved properties:

	Year Ended December 31,
(in millions)	2017		2016		2015
Total impairments	$	229	$	67	$	721

• 2017 - Impairments were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment of $136 million. Additionally, included in proved property impairments was $89 million relating to the Gulf of Mexico and certain conventional Oklahoma assets primarily as a result of lower forecasted long-term commodity prices.

• 2016 - Impairments of $67 million consisted primarily of proved properties in Oklahoma and the Gulf of Mexico as a result of lower forecasted commodity prices and revisions to estimated abandonment costs.

• 2015 - Impairments included $340 million for the goodwill impairment of the United States E&P reporting unit, and $335 million related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and $44 million associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma.

See Note 6 for relevant detail regarding segment presentation, Note 12 for further detail regarding the goodwill impairment and Note 14 for fair value measurements related to impairments of proved properties and long-lived assets.

Exploration expense

The following table summarizes the components of exploration expenses:

	Year Ended December 31,
(In millions)	2017		2016		2015
Exploration Expenses
Unproved property impairments	$	246	$	195	$	655
Dry well costs	77		25		212
Geological and geophysical	25		5		31
Other	61		98		73
Total exploration expenses	$	409	$	323	$	971

Unproved property impairments and dry well costs

• 2017 - As a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our International E&P segment, we recorded a non-cash charge of $159 million comprised of $95 million in unproved property impairments; and $64 million in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of Gabon, we recorded a non-cash impairment charge of $43 million to unproved property.

• 2016 - Unproved property impairments recorded of $195 million were primarily a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in the United States. Lower dry well expense was a result of the strategic decision to transition out of our conventional exploration program during 2015.

• 2015 - Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved property impairment mentioned above. Dry well costs include the operated Solomon exploration well in the Gulf of Mexico, and our operated Sodalita West #1 exploratory well in E.G.

See Note 6 for relevant detail regarding segment presentation of unproved property impairments.

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations were as follows:

	For Year Ended December 31,
(In millions)	2017			2016
Beginning balance	$	1,652		$	1,544
Incurred liabilities, including acquisitions	25			14
Settled liabilities, including dispositions	(50		)	(74		)
Accretion expense (included in depreciation, depletion and amortization)	85			79
Revisions of estimates	(227		)	96
Held for sale	(2		)	(7		)
Ending balance	$	1,483		$	1,652

2017

• Settled liabilities include dispositions, primarily related to the sale of certain conventional assets in Oklahoma as well as retirements in the U.K. and the Gulf of Mexico.

• Revisions of estimates were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.

• Ending balance includes $55 million classified as short-term at December 31, 2017.

2016

• Settled liabilities include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.

• Revisions of estimates were primarily due to changes in timing of abandonment activities as well as changes in cost estimated in the U.K.

• Ending balance includes $50 million classified as short-term at December 31, 2016.

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Goodwill (Notes)

12 Months Ended

Dec. 31, 2017

Goodwill Disclosure [Abstract]

Goodwill

Goodwill

Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. We performed our annual impairment test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40%. We believe the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in such assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2017 and 2016:

(In millions)	U.S. E&P		Int'l E&P		Total
2016
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115
2017
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115

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Derivatives

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 14. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our commodity derivatives and historical interest rate derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	December 31, 2017
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Not Designated as Hedges
Commodity	$	—	$	138	$	(138	)	Other current liabilities
Commodity	—		2		(2		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	140	$	(140	)
Total	$	—	$	140	$	(140	)

	December 31, 2016
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate	$	3	$	—	$	3		Other current assets
Interest rate	1		—		1			Other noncurrent assets
Cash Flow Hedges
Interest rate	$	64	$	—	$	64		Other noncurrent assets
Total Designated Hedges	$	68	$	—	$	68
Not Designated as Hedges
Commodity	$	—	$	60	$	(60	)	Other current liabilities
Total Not Designated as Hedges	$	—	$	60	$	(60	)
Total	$	68	$	60	$	8

Derivatives Designated as Fair Value Hedges

During the third quarter of 2017, we terminated all of our interest rate swaps designated as fair value hedges. The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income has a gross impact that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value hedges in all periods presented.

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”) based, floating rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	—	—	%	$	600	5.10	%
March 15, 2018	$	—	—	%	$	300	5.04	%

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income is summarized in the table below. There is no ineffectiveness related to the historical fair value hedges.

		Gain (Loss)
		Year Ended December 31,
(In millions)	Income Statement Location	2017		2016			2015
Derivative
Interest rate	Net interest and other	$	—	$	(4	)	$	—
Hedged Item
Debt	Net interest and other	$	—	$	4		$	—

Derivatives Not Designated as Hedges

Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow hedges. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. See Note 15 for further detail. As a result, we terminated our forward starting interest rate swaps receiving proceeds of $54 million. We recognized a gain of $47 million, related to deferred gains reclassified from accumulated other comprehensive income, in net interest and other during 2017.

The following table presents, by maturity date, information about our terminated forward starting interest rate swap agreements, including the rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR		Aggregate Notional Amount		Weighted Average, LIBOR
Maturity Dates	(in millions)		Fixed Rate		(in millions)		Fixed Rate
March 15, 2018	$	—	—	%	$	750	1.57	%

The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest Rate Swaps
Beginning balance	$	60		$	—		$	—
Change in fair value recognized in other comprehensive income	(13		)	64			—
Reclassification from other comprehensive income	(47		)	(4		)	—
Ending balance	$	—		$	60		$	—

Commodity Derivatives

We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States E&P sales through 2019. These commodity derivatives consist of three-way collars, swaps, and basis swaps. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of December 31, 2017 and the weighted average prices for those contracts:

Crude Oil
	2018				2019
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars (a)
Volume (Bbls/day)	85,000	85,000	85,000	85,000	10,000	10,000
Weighted average price per Bbl:
Ceiling	$56.38	$56.38	$56.96	$56.96	$60.00	$60.00
Floor	$51.65	$51.65	$51.53	$51.53	$55.00	$55.00
Sold put	$45.00	$45.00	$44.65	$44.65	$47.00	$47.00
Swaps
Volume (Bbls/day)	20,000	20,000	—	—	—	—
Weighted average price per Bbl	$55.12	$55.12	$—	$—	$—	$—
Basis Swaps (b)
Volume (Bbls/day)	5,000	5,000	10,000	10,000	—	—
Weighted average price per Bbl	$(0.60)	$(0.60)	$(0.67)	$(0.67)	$—	$—

^(a)  Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.

^(b)  The basis differential price is between WTI Midland and WTI Cushing.

Natural Gas
	2018
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	200,000	160,000	160,000	160,000
Weighted average price per MMBtu
Ceiling	$3.79	$3.61	$3.61	$3.61
Floor	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.50	$2.50	$2.50

The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the years ended December 31, 2017, 2016, and 2015. The December 31, 2017, 2016, and 2015 impact was a net loss of $36 million, a net loss of $66 million, and a net gain of $128 million, respectively. Net settlements of commodity derivative instruments for the years ended December 31, 2017, 2016, and 2015 were gains of $45 million, $44 million, and $78 million, respectively.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair values – Recurring

The following tables' present assets and liabilities accounted for at fair value on a recurring basis by hierarchy level.

	December 31, 2017
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	—			—			—		—
Derivative instruments, assets	$	—		$	—		$	—	$	—
Derivative instruments, liabilities
Commodity (a)	$	(20	)	$	(120	)	$	—	$	(140	)
Derivative instruments, liabilities	$	(20	)	$	(120	)	$	—	$	(140	)
	December 31, 2016
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	$	—		$	68		$	—	$	68
Derivative instruments, assets	$	—		$	68		$	—	$	68
Derivative instruments, liabilities
Commodity (a)	$	—		$	60		$	—	$	60
Derivative instruments, liabilities	$	—		$	60		$	—	$	60

^(a) Derivative instruments are recorded on a net basis in our balance sheet (see Note 13).

Commodity derivatives include three-way collars, swaps, and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include commodity prices and interest rates and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars, inputs to the models include commodity prices, interest rates, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Historically, both our interest rate swaps and forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 13 for additional discussion of the types of derivative instruments we use.  

Fair values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2017				2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	179	$	229	$	15	$	67	$	56	$	386

Long-lived assets held for use that were impaired are discussed below. The fair values, unless otherwise noted, were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.

United States E&P

In the third quarter of 2017, impairments of $65 million were recorded consisting of certain proved properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $66 million.

In the third quarter of 2016, impairments of $47 million were recorded consisting primarily of conventional non-core proved properties in Oklahoma as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $15 million. During the fourth quarter of 2016, we recorded an impairment of $17 million as a result of abandonment cost revisions related to the Ozona development in the Gulf of Mexico which ceased productions in 2013.

In the third quarter of 2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.

During the second quarter of 2015, we recorded an impairment charge of $44 million related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale. The fair values were measured using a probability weighted income approach based on both the anticipated sale price and held-for-use model.

International E&P

In the third quarter of 2017, we recorded proved property impairments of $136 million, to an aggregate fair value of $103 million, on certain non-core properties in our International E&P segment primarily as a result of lower forecasted long-term commodity prices and as a result of the anticipated sales of certain non-core international assets. The fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe. This resulted in a Level 2 classification. See Note5 for further information about the divestment of certain non-core properties in our International E&P segment.

In the third quarter of 2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, to a fair value of $604 million. The impairment was reflected in income from equity method investments in our consolidated statement of income.

Canadian discontinued operations

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 5 for relevant detail regarding dispositions

Fair values – Financial instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2017 and 2016.

	December 31,
	2017				2016
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other current assets (a)	$	762	$	761	$	7	$	7
Other noncurrent assets	159		161		105		108
Total financial assets	$	921	$	922	$	112	$	115
Financial liabilities
Other current liabilities	$	32	$	43	$	68	$	75
Long-term debt, including current portion (b)	5,976		5,526		7,449		7,292
Deferred credits and other liabilities	110		103		114		107
Total financial liabilities	$	6,118	$	5,672	$	7,631	$	7,474

^(a)  Includes our two notes receivable relating to the sale of our Canadian business as of December 31, 2017, see note 5 for further information.

^(b)  Excludes capital leases, debt issuance costs and historical interest rate swap adjustments.

Fair values of our notes receivable and our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

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Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

Debt

Short-term debt

As of December 31, 2017, we had no borrowings against our $3.4 billion unsecured revolving credit facility (as amended, the "Credit Facility"), as described below.

Revolving Credit Facility

In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. 

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of December 31, 2017, we were in compliance with this covenant with a debt-to-capitalization ratio of 32%.

Long-term debt

The following table details our long-term debt:

	December 31,
(In millions)	2017			2016
Senior unsecured notes:
6.000% notes due 2017	—			682
5.900% notes due 2018	—			854
7.500% notes due 2019	—			228
2.700% notes due 2020(a)	600			600
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022 (b)	32			32
Series A notes due 2022 (b)	3			3
8.500% notes due 2023 (b)	70			70
8.125% notes due 2023 (b)	131			131
3.850% notes due 2025(a)	900			900
4.400% notes due 2027(a)	1,000			—
6.800% notes due 2032(a)	550			550
6.600% notes due 2037(a)	750			750
5.200% notes due 2045(a)	500			500
Capital leases:
Capital lease obligation expiring in 2018	—			1
Other obligations:
5.125% obligation relating to revenue bonds due 2037	—			1,000
Total(b)	5,536			7,301
Unamortized discount	(10		)	(9		)
Fair value adjustments(c)	—			7
Unamortized debt issuance cost	(32		)	(35		)
Amounts due within one year	—			(683		)
Total long-term debt	$	5,494		$	6,581

^(a)  These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2017 may be declared immediately due and payable.

^(c)  See Notes 13 and 14 for information on historical interest rate swaps.

Debt Issuance

On July 24, 2017, we issued $1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the senior unsecured notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior unsecured notes at any time at the applicable redemption price, plus accrued interest, if any. During the third quarter of 2017, we used the net proceeds of $990 million plus existing cash on hand to redeem the following senior unsecured notes:

• $682 million6.0% Notes Due in 2017

• $854 million5.9% Notes Due in 2018

• $228 million7.5% Notes Due in 2019

During the year ended 2017, as a result of the above redemption of $1.76 billion in senior unsecured notes, we recognized a loss on early extinguishment of debt of $46 million, primarily due to make-whole call provisions. In connection with the redemption of the senior unsecured notes, we terminated our forward starting interest rate swaps, which resulted in proceeds of $54 million and a gain of approximately $47 million into earnings in 2017. See Note 13 for further detail on our historical forward starting interest rate swaps.

Debt Redemption

In December 2017, we entered into a transaction to purchase $1 billion of 3.75% municipal revenue bonds due in 2037, to be issued by the Parish of St. John the Baptist, State of Louisiana (the "Parish"). The Parish will use the proceeds to redeem $1 billion of 5.125% municipal revenue bonds due in 2037 with cash on hand in a refunding transaction. We purchased the $1 billion of 3.75% municipal revenue bonds due in 2037 on their date of issuance to hold for our own account and potential remarketing to the public at a future date.

The following table shows future debt payments:

(In millions)
2018	$	—
2019	—
2020	600
2021	—
2022	1,035
Thereafter	3,901
Total long-term debt, including current portion	$	5,536

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Incentive Based Compensation Plans

12 Months Ended

Dec. 31, 2017

Incentive Based Compensation Plans [Abstract]

Incentive Based Compensation

Incentive Based Compensation

Description of stock-based compensation plans – The Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan") was approved by our stockholders in May 2016 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance unit awards to employees. The 2016 Plan also allows us to provide equity compensation to our non-employee directors. No more than 55 million shares of our common stock may be issued under the 2016 Plan. For stock options and SARs, the number of shares available for issuance under the 2016 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted. For stock awards (including restricted stock and restricted stock unit awards), the number of shares available for issuance under the 2016 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.

Shares subject to awards under the 2016 Plan that are forfeited, terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2016 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2016 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

After approval of the 2016 Plan, no new grants were or will be made from any prior plans. Any awards previously granted under any prior plans shall continue to be exercisable in accordance with their original terms and conditions.

Stock-based awards under the plans

Stock options – We grant stock options under the 2016 Plan. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

SARs - At December 31, 2017, there are no SARs outstanding.

Restricted stock – We grant restricted stock under the 2016 Plan. The restricted stock awards granted to officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest ratably over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares of restricted stock are not transferable and are held by our transfer agent.

Stock-based performance units – We grant stock-based performance units to officers under the 2016 Plan. At the grant date, each unit represents the value of one share of our common stock. These units are settled in cash, and the amount of the payment is based on (1) the vesting percentage, which can be from zero to 200% based on performance achieved and (2) the value of our common stock on the date vesting is determined by the Compensation Committee of the Board of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the performance period and would be paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.

Restricted stock units – We maintain an equity compensation program for our non-employee directors.  All non-employee directors receive annual grants of common stock units.  Any units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares.  For units granted between 2012 and 2016, common shares will generally vest following completion of board service or three years from the date of grant, whichever is earlier.  For awards issued in 2017 and later, directors may elect to defer settlement of their common stock units until after they cease serving on the Board.  Absent such an election to defer, common shares will vest upon the earlier of three years from the date of grant or completion of board service.  We also grant restricted stock units to certain non-officer international employees which generally vest ratably over a three-year period, contingent on the recipient's continued employment. Grants of restricted stock units to these non-officer international employees are based on their performance and for retention purposes. Common shares will be issued for these restricted stock units after vesting. Prior to vesting, recipients of restricted stock units typically receive dividend equivalent payments, but they may not vote.

Total stock-based compensation expense – Total employee stock-based compensation expense was $50 million, $51 million and $57 million in 2017, 2016 and 2015, while the total related income tax benefits were $19 million and $20 million in 2016 and 2015. Due to the full valuation allowance on our net federal deferred tax assets, we realized no tax benefit during 2017. During 2016 and 2015, cash received upon exercise of stock option awards was $1 million and $9 million. There was no cash received upon exercise of stock option awards for 2017. There were no tax benefits realized for deductions for stock awards settled during 2017, 2016 and 2015.

Stock option awards – During 2017, 2016 and 2015 we granted stock option awards to officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2017		2016		2015
Exercise price per share	$15.80		$7.22		$29.06
Expected annual dividend yield	1.3	%	2.8	%	2.9	%
Expected life in years	6.4		6.3		6.2
Expected volatility	42	%	36	%	32	%
Risk-free interest rate	2.1	%	1.4	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$6.07		$1.97		$6.84

The following is a summary of stock option award activity in 2017.

	Number	Weighted Average	Weighted Average Remaining	Aggregate Intrinsic Value
	of Shares	Exercise Price	Contractual Term	(in millions)
Outstanding at beginning of year	11,915,533	$27.71
Granted	799,591	$15.80
Exercised	(8,666)	$7.22
Canceled	(2,375,682)	$33.31
Outstanding at end of year	10,330,776	$25.52	4 years	$	13
Exercisable at end of year	8,661,893	$27.91	3 years	$	5
Expected to vest	1,650,737	$13.08	9 years	$	8

The intrinsic value of stock option awards exercised during 2017 and 2016 were not material. The intrinsic value of stock awards exercised during 2015 was $6 million.

As of December 31, 2017, unrecognized compensation cost related to stock option awards was $4 million, which is expected to be recognized over a weighted average period of one year.

Restricted stock awards and restricted stock units – The following is a summary of restricted stock and restricted stock unit award activity in 2017.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	6,933,533		$14.44
Granted	4,198,624		$16.13
Vested & Exercised	(2,472,367	)	$17.67
Canceled	(1,086,945	)	$15.03
Unvested at end of year	7,572,845		$14.24

The vesting date fair value of restricted stock awards which vested during 2017, 2016 and 2015 was $30 million, $16 million and $26 million. The weighted average grant date fair value of restricted stock awards was $14.24, $14.44 and $30.76 for awards unvested at December 31, 2017, 2016 and 2015.

As of December 31, 2017 there was $67 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of one year.

Stock-based performance unit awards – During 2017, 2016 and 2015 we granted 563,631, 1,205,517 and 382,335 stock-based performance unit awards to officers. At December 31, 2017, there were 1,510,823 units outstanding. Total stock-based performance unit awards expense was $8 million in 2017 and $6 million in 2016. We had no stock-based performance unit awards expense in 2015.

The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units granted in 2017, 2016 and 2015 were:

	2017		2016		2015 (a)
Valuation date stock price	$16.93		$16.93		$16.93
Expected annual dividend yield	1.2	%	1.2	%	1.2	%
Expected volatility	54	%	34	%	33	%
Risk-free interest rate	1.9	%	1.7	%	1.4	%
Fair value of stock-based performance units outstanding	$21.63		$19.86		$0.00

^(a) As of December 31, 2017, there were no 2015 performance unit awards outstanding.

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Notes)

12 Months Ended

Dec. 31, 2017

Defined Benefit Plan [Abstract]

Defined Benefit Postretirement Plans and Defined Contribution Plan

Defined Benefit Postretirement Plans and Defined Contribution Plan

We have noncontributory defined benefit pension plans covering substantially all domestic employees, as well as U.K. employees who were hired before April 2010. Certain employees located in E.G., who are U.S. or U.K. based, also participate in these plans. Benefits under these plans are based on plan provisions specific to each plan. For the U.K. pension plan, the principal employer and plan trustees reached a decision to close the plan to future benefit accruals effective December 31, 2015.

We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided up to age 65 through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Post-age 65 health care benefits are provided to certain U.S. employees on a defined contribution basis. Life insurance benefits are provided to certain retiree beneficiaries. These other postretirement benefits are not funded in advance. Employees hired after 2016 are not eligible for any postretirement health care or life insurance benefits.

Obligations and funded status– The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.    

	Pension Benefits												Other Benefits
	2017						2016						2017			2016
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			U.S.
Accumulated benefit obligation	378			599			386			583			221			227
Change in benefit obligations:
Beginning balance	$	397		$	583		$	525		$	579		$	227		$	260
Service cost	22			—			25			—			2			2
Interest cost	13			17			16			23			8			11
Plan amendment	—			—			—			1			—			(38		)
Actuarial loss (gain)	42			(7		)	78			139			5			11
Foreign currency exchange rate changes	—			52			—			(108		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(19		)
Ending balance	$	384		$	599		$	397		$	583		$	221		$	227
Change in fair value of plan assets:
Beginning balance	$	227		$	595		$	354		$	608		$	—		$	—
Actual return on plan assets	27			47			25			129			—			—
Employer contributions	52			17			95			18			21			20
Foreign currency exchange rate changes	—			57			—			(109		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(20		)
Ending balance	$	216		$	670		$	227		$	595		$	—		$	—
Funded status of plans at December 31	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	—			71			—			12			—			—
Current liabilities	(6		)	—			(4		)	—			(21		)	(21		)
Noncurrent liabilities	(162		)	—			(166		)	—			(200		)	(206		)
Accrued benefit cost	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	122		$	58		$	130		$	81		$	30		$	25
Prior service cost (credit)	(45		)	3			(55		)	4			(56		)	(63		)

Components of net periodic benefit cost from continuing operations and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits																		Other Benefits
	Year Ended December 31,																		Year Ended December 31,
	2017						2016						2015						2017			2016			2015
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			U.S.			U.S.			U.S.
Components of net periodic benefit cost:
Service cost	$	22		$	—		$	25		$	—		$	29		$	14		$	2		$	2		$	3
Interest cost	13			17			16			23			25			25			8			11			11
Expected return on plan assets	(13		)	(30		)	(18		)	(35		)	(30		)	(37		)	—			—			—
Amortization:
- prior service cost (credit)	(10		)	—			(10		)	1			(7		)	1			(7		)	(3		)	(4		)
- actuarial loss	8			1			14			—			22			2			—			—			1
Net curtailment loss (gain)(a)	—			—			—			—			(5		)	4			—			—			(7		)
Net settlement loss(b)	28			4			97			6			119			—			—			—			—
Net periodic benefit cost(c)	$	48		$	(8	)	$	124		$	(5	)	$	153		$	9		$	3		$	10		$	4
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	28		$	(26	)	$	70		$	41		$	30		$	(25	)	$	5		$	11		$	(21	)
Amortization of actuarial gain (loss)	(36		)	(4		)	(111		)	(6		)	(134		)	(2		)	—			—			(1		)
Prior service cost (credit)	—			—			—			1			(89		)	1			—			(38		)	—
Amortization of prior service credit (cost)	10			—			10			(1		)	7			(5		)	7			3			13
Total recognized in other comprehensive (income) loss	$	2		$	(30	)	$	(31	)	$	35		$	(186	)	$	(31	)	$	12		$	(24	)	$	(9	)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	50		$	(38	)	$	93		$	30		$	(33	)	$	(22	)	$	15		$	(14	)	$	(5	)

^(a)  Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.

^(b)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.

^(c)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are $13 million and $10 million. The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2018 are $1 million and $7 million.

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2017, 2016 and 2015.

	Pension Benefits												Other Benefits
	2017				2016				2015				2017		2016		2015
(In millions)	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		U.S.		U.S.
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.55	%	2.50	%	4.02	%	2.70	%	4.04	%	3.90	%	3.54	%	3.98	%	4.36	%
Rate of compensation increase (a)	4.00	%	—		4.00	%	—		4.00	%	—		4.00	%	4.00	%	4.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.86	%	2.70	%	3.66	%	3.90	%	3.79	%	3.70	%	3.98	%	4.36	%	3.93	%
Expected long-term return on plan assets	6.50	%	4.50	%	6.75	%	5.50	%	6.75	%	5.70	%	—		—		—
Rate of compensation increase (a)	4.00	%	—		4.00	%	—	%	4.00	%	3.60	%	4.00	%	4.00	%	4.00	%

^(a)  No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.

Expected long-term return on plan assets – The expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group which utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation. To determine the expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation to develop the overall expected long-term return on plan assets assumption.

Assumed weighted average health care cost trend rates

	2017		2016		2015
Initial health care trend rate	8.00	%	8.25	%	8.00	%
Ultimate trend rate	4.70	%	4.50	%	4.50	%
Year ultimate trend rate is reached	2025		2025		2024

Employer provided subsidies for post-65 retiree health care coverage were frozen effective January 1, 2017 at January 1, 2016 established amount levels. Company contributions are funded to a Health Reimbursement Account on the retiree’s behalf to subsidize the retiree’s cost of obtaining health care benefits through a private exchange. Therefore, a 1% change in health care cost trend rates would not have a material impact on either the service and interest cost components and the postretirement benefit obligations.

Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with applicable legal requirements; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plan's investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

U.S. plan – The plan’s current targeted asset allocation is comprised of 55% equity securities and 45% other fixed income securities. Over time, as the plan’s funded ratio (as defined by the investment policy) improves, in order to reduce volatility in returns and to better match the plan’s liabilities, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. The plan's assets are managed by a third-party investment manager.

International plan – Our international plan's target asset allocation is comprised of 55% equity securities and 45% fixed income securities. The plan assets are invested in ten separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers whose performance is measured independently by a third-party asset servicing consulting firm.

Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2017 and 2016.

Cash and cash equivalents – Cash and cash equivalents are valued using a market approach and are considered Level 1. This investment also includes a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2.

Equity securities -Investments in common stock and preferred stock are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership. These private equity investments are considered Level 3. Investments in pooled funds are valued using a market approach at the net asset value ("NAV") of units held. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Fixed income securities - Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds ("ETFs") are valued at the closing price reported in an active market and are considered Level 1. Corporate bonds, non-U.S. government bonds, private placements, taxable municipals, GNMA/FNMA pools, and Yankee bonds are valued using calculated yield curves created by models that incorporate various market factors. Primarily investments are held in U.S. and non-U.S. corporate bonds in diverse industries and are considered Level 2. Other fixed income investments include futures contracts, real estate investment trusts, credit default, zero coupon, and interest rate swaps. The investment in the commingled funds is valued using the NAV of units held as a practical expedient. The commingled funds consist of equity and fixed income portfolios with underlying investments held in U.S. and non-U.S. securities. Pooled funds primarily have investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds and are considered Level 2.

Other – Other investments are comprised of an unallocated annuity contract, two limited liability companies, real estate and U.S. treasury futures. All are considered Level 3, as significant inputs to determine fair value are unobservable.

The following tables present the fair values of our defined benefit pension plan's assets, by level within the fair value hierarchy, as of December 31, 2017 and 2016.

	December 31, 2017
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	6	$	1	$	—	$	—	$	—	$	—	$	6	$	1
Equity securities:
Common stock	81		—		—		—		—		—		81		—
Private equity	—		—		—		—		16		—		16		—
Mutual and pooled funds	—		151		—		115		—		—		—		266
Fixed income securities:
Corporate	—		—		6		—		—		—		6		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	19		—		2		—		3		—		24		—
Pooled funds	—		—		—		403		—		—		—		403
Other	—		—		—		—		19		—		19		—
Total investments, at fair value	111		152		8		518		38		—		157		670
Commingled funds (a)	—		—		—		—		—		—		59		—
Total investments	$	111	$	152	$	8	$	518	$	38	$	—	$	216	$	670

	December 31, 2016
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	8	$	5	$	—	$	—	$	—	$	—	$	8	$	5
Equity securities:
Common stock	82		—		—		—		—		—		82		—
Private equity	—		—		—		—		20		—		20		—
Mutual and pooled funds	—		201		—		159		—		—		—		360
Fixed income securities:
Corporate	—		—		52		—		—		—		52		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	6		—		19		—		—		—		25		—
Pooled funds	—		—		—		230		—		—		—		230
Other	—		—		—		—		21		—		21		—
Total investments, at fair value	101		206		71		389		41		—		213		595
Commingled funds (a)	—		—		—		—		—		—		14		—
Total investments	$	101	$	206	$	71	$	389	$	41	$	—	$	227	$	595

^(a) After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update.

The activity during the year ended December 31, 2017 and 2016, for the assets using Level 3 fair value measurements was immaterial.

Cash flows

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2017 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l		U.S.
2018	$	43	$	17	$	21
2019	40		18		20
2020	37		17		20
2021	33		19		19
2022	30		21		18
2023 through 2027	123		118		74

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $65 millionin 2018. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $6 million and $21 million in 2018.

Contributions to defined contribution plans – We contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $20 million, $20 million and $20 million in 2017, 2016 and 2015.

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Reclassifications Out of Accumulated Other Comprehensive Income (Notes)

12 Months Ended

Dec. 31, 2017

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassification out of AOCI [Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:

	Year Ended December 31,
(In millions)	2017			2016			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(9	)	$	(14	)	General and administrative
Net settlement loss	(32		)	(103		)	General and administrative
Derivative hedges
Recognized gain on terminated derivative hedge	46			—			Net interest and other
Ineffective portion of derivative hedge	1			4			Net interest and other
	6			(113		)	Income (loss) from operations
	(40		)	41			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	$	(34	)	$	(72	)	Income (loss) from continuing operations
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	(30		)	—			Income (loss) from discontinued operations
Total reclassifications to expense	$	(64	)	$	(72	)

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

	Year Ended December 31,
(In millions)	2017			2016			2015
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(379	)	$	(375	)	$	(325	)
Income taxes paid to taxing authorities  (a)	(391		)	(84		)	(171		)
Noncash investing activities, related to continuing operations:
Changes in asset retirement costs	$	(202	)	$	110		$	(95	)
Asset retirement obligations assumed by buyer	14			40			251
Increase in capital expenditure accrual	176			—			—
Notes receivable for disposition of assets	748			—			—

^(a) Includes a payment of $108 million made to U.K. taxing authorities to preserve our appeal rights, see Note 7 - Income Taxes for additional discussion.

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Other Items

12 Months Ended

Dec. 31, 2017

Interest and Other Income [Abstract]

Interest and Other Income [Text Block]

Other Items

Net interest and other

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest:
Interest income	$	34		$	14		$	9
Interest expense	(380		)	(398		)	(350		)
Income on interest rate swaps	53			13			11
Interest capitalized	3			18			19
Total interest	(290		)	(353		)	(311		)
Other:
Net foreign currency gain (loss)	8			6			4
Other	12			15			21
Total other	20			21			25
Net interest and other	$	(270	)	$	(332	)	$	(286	)

Foreign currency – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

	Year Ended December 31,
(In millions)	2017		2016			2015
Net interest and other	$	8	$	6		$	4
Provision for income taxes	57		(32		)	(11		)
Aggregate foreign currency gains (losses)	$	65	$	(26	)	$	(7	)

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Equity Method Investments and Related Party Transactions (Notes)

12 Months Ended

Dec. 31, 2017

Equity Method Investments Disclosure [Abstract]

Equity Method Investments and Related Party Transactions

Equity Method Investments and Related Party Transactions

During 2017, 2016 and 2015 only our equity method investees were considered related parties and they included:

• EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.

•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.

• AMPCO, in which we have a 45% interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2017	2017		2016
EGHoldings	60%	$	456	$	550
Alba Plant LLC	52%	214		215
AMPCO	45%	177		165
Other investments		—		1
Total		$	847	$	931

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $276 million in 2017, $192 million in 2016 and $178 million in 2015.

Summarized financial information for equity method investees is as follows:

(In millions)	2017		2016		2015
Income data – year (a):
Revenues and other income	$	1,294	$	770	$	769
Income from operations	631		346		313
Net income	508		313		280
Balance sheet data – December 31:
Current assets	$	586	$	525
Noncurrent assets	1,044		1,173
Current liabilities	221		218
Noncurrent liabilities	94		47

^(a)  See Item 15 Exhibits, Financial Statement Schedules which contains the Alba Plant LLC audited financial statements, which have been included pursuant to Rule 3-09 of Regulation S-X.

Revenues from related parties were $60 million, $54 million and $51 million in 2017, 2016 and 2015, with the majority related to EGHoldings in all years. Purchases from related parties were $132 million, $103 million and $207 million in 2017, 2016 and 2015 with the majority related to Alba Plant LLC in all years.

Current receivables from related parties at December 31, 2017 and 2016, were $24 million, and $23 million. Payables to related parties were $14 million and $11 million at December 31, 2017 and 2016, with the majority related to Alba Plant LLC.

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Stockholders Equity (Notes)

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders’ Equity

Stockholders’ Equity

In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Development Program.

There were no share repurchases during 2017 or 2016 under our publicly announced plans or programs. As of December 31, 2017 the total remaining share repurchase authorization was $1.5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables.

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Leases (Notes)

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Leases

Leases

We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Operating Lease Obligations
2018	$	29
2019	28
2020	27
2021	26
2022	5
Later years	4
Sublease rentals	—
Total minimum lease payments	$	119

^* Future minimum commitments for capital lease obligations are nil as of December 31, 2017.

Operating lease rental expense related to continuing operations was $87 million, $87 million and $99 million in 2017, 2016 and 2015.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs, which we claimed for U.K. corporation tax purposes.  The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In the third quarter of 2017, a hearing took place at the U.K.’s First-tier Tribunal with respect to this tax deduction.  In the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the judge sided with the U.K. tax authorities with respect to the timing of the decommissioning cost deductions.  We intend to appeal this decision and estimate that any revisions to current and deferred tax liabilities, if we do not prevail in the appeals process, would have no cumulative adverse earnings impact on our consolidated results of operations.  In accordance with U.K. regulations, we have paid the amount of tax and interest in question, approximately $108 million, prior to our appeal.  As a result of the negative ruling we no longer consider this position to be more-likely-than-not to be sustained and have created an uncertain tax position related to the Brae area decommissioning costs.  The payment of the tax and interest to the U.K. tax authorities is not to settle the position, but a regulatory requirement to appeal in the U.K.  If we ultimately prevail in appeals, the U.K. tax authorities will refund the tax and interest, however, if we ultimately lose in appeals no material future payments related to this issue will be required.  See Note 7 for further detail.

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS.  These audits have been completed through the 2014 tax year, except for tax years 2010 and 2011. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the fourth quarter of 2017.  We believe that it is more likely than not that we will prevail.

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.

Environmental matters – We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of federal, state, local and foreign laws and regulations relating to the environment. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected.  We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

At December 31, 2017 and 2016, accrued liabilities for remediation were not material. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.

Guarantees – We have entered into a performance guarantee related to asset retirement obligations with aggregate maximum potential undiscounted payments totaling $35 million as of December 31, 2017. Under the terms of this guarantee arrangement, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.

Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contract commitments – At December 31, 2017 and 2016, contractual commitments to acquire property, plant and equipment totaled $102 million and $144 million.

In connection with the sale of our operated producing properties in the greater Ewing Bank area and non-operated producing interests in the Petronius and Neptune fields in the Gulf of Mexico, we retained an overriding royalty interest in the properties. As part of the sale agreement, proceeds associated with the production of our override, up to $70 million, are dedicated solely to the satisfaction of the corresponding future abandonment obligations of the properties. The term of our override ends once sales proceeds equal $70 million.

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Summary of Principal Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Principles applied in consolidation

Basis of presentation and principles applied in consolidation – These consolidated financial statements include the accounts of our controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments– Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees and is reflected in revenue and other income in our consolidated statements of income. Equity method investments are included as noncurrent assets on the consolidated balance sheet.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred and is other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Reclassifications – We have reclassified certain prior year amounts between operating cash flow categories to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.

Discontinued operations – As a result of the sale of our Canadian business in 2017, we reflected this business as discontinued operations in all periods presented. Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Assets and liabilities are presented as held for sale in the historical periods in the consolidated balance sheets. See Note 5 for discussion of the divestiture in further detail.

As discussed above we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases in the second quarter 2017. The characteristics and composition of our North America E&P reporting segment remained unchanged and there was no effect on previously reported segment information. As all our remaining properties within the segment are located within the United States, we concluded that our North America E&P segment would be renamed United States E&P segment, effective June 30, 2017. During the year, no changes occurred to our International E&P segment. See Note 6 for further information on our reportable segments.

Use of estimates

Use of estimates – The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Foreign currency transactions

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of crude oil and condensate, NGLs and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time.

Gas balancing policy

We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

Cash and cash equivalents

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Investment, Policy [Policy Text Block]

Short-term Investments - Our short-term investments are comprised of bank time deposits with original maturities of greater than three months but less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost.

Accounts receivable

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. We routinely assess the collectability of receivable balances to determine if the amount of the reserve in allowance for doubtful accounts is sufficient.

Notes receivable - We hold two notes receivable from the sale of our Canadian business, which closed in the second quarter of 2017. Both notes receivable were initially recorded at fair value and are reported at amortized cost. The notes receivable are evaluated for collectability on an individual basis each reporting period, based on the financial condition of the debtor. No allowances for credit losses were established for the notes receivable as of December 31, 2017. See Note 5 for additional discussion.

Inventories

Inventories – Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, commodity locational risk, foreign currency risk and interest rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities. Our derivative instruments contain no significant contingent credit features.

Hedges

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Cash flow hedges – We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. Derivative instruments designated as cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The effective portion of changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income until the hedged item is reclassified to net income when the underlying forecasted transaction is recognized in net income. Ineffective portions of a cash flow hedge’s change in fair value are recognized currently within net interest and other on the consolidated statements of income. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in other comprehensive income is immediately reclassified into net income.

Derivatives not designated as hedges

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price and locational risks on the forecasted sale of crude oil and natural gas that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income

Concentrations of credit risk

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Fair value transfer

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. If significant transfers occur, they would be disclosed in Note 14 to the consolidated financial statements.

Property, plant and equipment

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities.

Property acquisition costs

Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells in progress and those that find proved reserves, and to drill development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities, as well as property, plant and equipment unrelated to oil and gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets as summarized below.

Type of Asset	Range of Useful Lives
Office furniture, equipment and computer hardware	4 to 15 years
Pipelines	10 to 40 years
Plants, facilities and infrastructure	3 to 40 years

Impairments

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells and development costs, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, this amount is reported in exploration expenses in our consolidated statements of income.

Dispositions

Dispositions – When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reflected in net gain (loss) on disposal of assets in our consolidated statements of income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized either when the assets are classified as held for sale, or are measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model depending on timing of the sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to a reporting unit. The fair value of a reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

Major maintenance activities

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs

Environmental costs – We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable. Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets.

Asset retirement obligations

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production facilities and equipment, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis based on estimated proved developed reserves for oil and gas production facilities, while accretion of the liability occurs over the useful lives of the assets

Deferred income taxes

Deferred income taxes – Deferred tax assets and liabilities, measured at enacted tax rates, are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include whether we are in a cumulative loss position in recent years, our reversal of temporary differences, and our expectation to generate sufficient future taxable income. We use the liability method in determining our provision and liabilities for our income taxes, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates.

Stock based compensation arrangements

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected volatility of our stock price and the stock price in relation to the strike price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employees' behalf are presented within the financing activities section instead of the operating activities section of the statement of cash flows. We elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for the years ended December 31, 2016 or 2015. Excess tax benefits were classified as an operating activity within the statement of cash flows on a prospective basis beginning in 2017; as such, prior periods were not adjusted. See Note 2 for additional discussion.

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Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The per share calculations below exclude 11 million, 13 million and 13 million stock options in 2017, 2016 and 2015 that were antidilutive.

	Year Ended December 31,
(In millions, except per share data)	2017			2016			2015
Income (loss) from continuing operations	$	(830	)	$	(2,087	)	$	(1,701	)
Income (loss) from discontinued operations	(4,893		)	(53		)	(503		)
Net income (loss)	$	(5,723	)	$	(2,140	)	$	(2,204	)
Weighted average common shares outstanding	850			819			677
Per basic share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)
Per diluted share:
Income (loss) from continuing operations	$	(0.97	)	$	(2.55	)	$	(2.51	)
Income (loss) from discontinued operations	$	(5.76	)	$	(0.06	)	$	(0.75	)
Net income (loss)	$	(6.73	)	$	(2.61	)	$	(3.26	)

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Dispositions (Tables)

12 Months Ended

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures

The following table contains select amounts reported in our consolidated statements of income as discontinued operations:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total sales and other revenues and other income	$	431		$	863		$	908
Net gain (loss) on disposal of assets	(43		)	—			—
Total revenues and other income	388			863			908
Costs and expenses:
Production expenses	254			601			715
Exploration expenses	—			7			347
Depreciation, depletion and amortization	40			239			236
Impairments	6,636			—			31
Other	25			87			98
Total costs and expenses	6,955			934			1,427
Pretax income (loss) from discontinued operations	(6,567		)	(71		)	(519		)
Provision (benefit) for income taxes	(1,674		)	(18		)	(16		)
Income (loss) from discontinued operations	$	(4,893	)	$	(53	)	$	(503	)

The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and other non-core international assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at December 31, 2017 and December 31, 2016:

	December 31,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	—	$	2
Accounts receivables	—		129
Inventories	—		91
Other	—		4
Total current assets held for sale—discontinued operations	—		226
Total current assets held for sale—continuing operations	11		1
Total current assets held for sale	$	11	$	227
Noncurrent assets:
Property, plant and equipment, net	$	—	$	8,991
Other	—		106
Total noncurrent assets held for sale—discontinued operations	—		9,097
Total noncurrent assets held for sale—continuing operations	55		1
Total noncurrent assets held for sale	$	55	$	9,098
Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	111
Other	—		10
Total current liabilities held for sale—discontinued operations	—		121
Total current liabilities held for sale—continuing operations	—		—
Total current liabilities held for sale	$	—	$	121
Noncurrent liabilities:
Asset retirement obligations	$	—	$	95
Deferred tax liabilities	—		1,669
Other	—		20
Total noncurrent liabilities held for sale—discontinued operations	—		1,784
Total noncurrent liabilities held for sale—continuing operations	2		7
Total noncurrent liabilities held for sale	$	2	$	1,791

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Year Ended December 31, 2017						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,138		$	1,154	$	(81	)	(b)	$	4,211
Marketing revenues	29			133		—				162
Total revenues	3,167			1,287		(81		)		4,373
Income from equity method investments	—			256		—				256
Net gain on disposal of assets and other income	13			6		117			(c)	136
Less:
Production expenses	476			229		1				706
Marketing costs	36			132		—				168
Other operating	354			77		—				431
Exploration	154			5		250			(d)	409
Depreciation, depletion and amortization	2,011			328		33				2,372
Impairments	4			—		225			(e)	229
Taxes other than income	173			—		10				183
General and administrative	119			32		249			(f)	400
Net interest and other	—			—		270			(g)	270
Loss on early extinguishment of debt	—			—		51			(h)	51
Income tax provision (benefit)	1			372		3				376
Segment income (loss) / Income (loss) from continuing operations	$	(148	)	$	374	$	(1,056	)		$	(830	)
Capital expenditures (a)	$	2,081		$	42	$	27			$	2,150

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to sale of certain conventional assets in Oklahoma and Colorado. (See Note 5).

^(d) Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(e)  Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 10).

^(f)   Includes pension settlement loss of $32 million (see Note 17).

^(g) Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 13.)

^(h) Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 15.)

Year Ended December 31, 2016						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	2,375		$	665	$	(110	)	(b)	$	2,930
Marketing revenues	135			105		—				240
Total revenues	2,510			770		(110		)		3,170
Income (loss) from equity method investments	—			175		—				175
Net gain on disposal of assets and other income	28			32		382			(c)	442
Less:
Production expenses	486			226		—				712
Marketing costs	142			103		—				245
Other operating	328			43		113			(d)	484
Exploration	127			17		179			(e)	323
Depreciation, depletion and amortization	1,835			276		45				2,156
Impairments	20			—		47			(f)	67
Taxes other than income	149			—		2				151
General and administrative	94			35		352			(g)	481
Net interest and other	—			—		332				332
Income tax provision (benefit)	(228		)	49		1,102			(h)	923
Segment income (loss) / Income (loss) from continuing operations	$	(415	)	$	228	$	(1,900	)		$	(2,087	)
Capital expenditures (a)	$	936		$	82	$	18			$	1,036

^(a)  Includes accruals.

^(b)  Unrealized loss on commodity derivative instruments.

^(c)  Primarily related to net gain on disposal of assets(see Note 5).

^(d)  Includes termination payment on our Gulf of Mexico deepwater drilling rig commitment of $113 million.

^(e) Primarily related to impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases (See Note 10).

^(f)  Proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $103 million and severance related expenses associated with workforce reductions of $8 million (see Note 17).

^(h)  Increased valuation allowance on certain of our deferred tax assets $1,346 million (see Note 7).

Year Ended December 31, 2015						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	3,358		$	728	$	50		(b)	$	4,136
Marketing revenues	396			103		—				499
Total revenues	3,754			831		50				4,635
Income from equity method investments	—			157		(12		)	(c)	145
Net gain on disposal of assets and other income	24			27		122			(d)	173
Less:
Production expenses	724			255		—				979
Marketing costs	401			99		—				500
Other operating	335			48		27				410
Exploration	314			101		556			(e)	971
Depreciation, depletion and amortization	2,377			295		49				2,721
Impairments	2			—		719			(f)	721
Taxes other than income	215			—		1				216
General and administrative	127			44		417			(g)	588
Net interest and other	—			—		286				286
Income tax provision (benefit)	(265		)	61		(534		)		(738		)
Segment income (loss) / Income (loss) from continuing operations	$	(452	)	$	112	$	(1,361	)		$	(1,701	)
Capital expenditures (a)	$	2,553		$	368	$	25			$	2,946

^(a)  Includes accruals.

^(b)  Unrealized gain on commodity derivative instruments.

^(c)  Partial impairment of investment in equity method investee (See Note 14).

^(d)  Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage(see Note 5).

^(e) Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 10).

^(f)  Includes goodwill impairment (see Note 12) and proved property impairments (see Note 10).

^(g)   Includes pension settlement loss of $119 million (see Note 17) and severance related expenses associated with workforce reductions of $55 million.

Schedule of Revenue from External Customers Attributed to Foreign Countries by Geographic Area

The following summarizes revenues from external customers by geographic area.

	Year Ended December 31,
(In millions)	2017		2016		2015
United States	$	3,086	$	2,400	$	3,804
Equatorial Guinea	530		444		444
Libya	431		54		—
U.K.	289		263		380
Other international	37		9		7
Total revenues	$	4,373	$	3,170	$	4,635

Revenue from External Customers by Products and Services

The following summarizes revenues by product line.

	Year Ended December 31,
(In millions)	2017		2016		2015
Crude oil and condensate	$	3,477	$	2,605	$	3,963
Natural gas liquids	338		198		203
Natural gas	510		356		464
Other	48		11		5
Total revenues	$	4,373	$	3,170	$	4,635

Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country

The following summarizes property, plant and equipment and equity method investments.

	December 31,
(In millions)	2017		2016
United States	$	15,971	$	14,272
Equatorial Guinea	1,582		1,794
Other international	959		1,592
Total long-lived assets	$	18,512	$	17,658

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Income before Income Tax, Domestic and Foreign

Income (loss) before tax expense for continuing operations was:

	Year Ended December 31,
(In millions)		2017			2016			2015
United States		$	(783	)	$	(1,449	)	$	(2,384	)
Foreign		329			285			(55		)
Total		$	(454	)	$	(1,164	)	$	(2,439	)

Schedule of Components of Income Tax Expense (Benefit)

Income tax provisions (benefits) for continuing operations were:

	Year Ended December 31,
	2017									2016							2015
(In millions)	Current			Deferred			Total			Current		Deferred			Total		Current			Deferred			Total
Federal	$	(32	)	$	41		$	9		$	2	$	836		$	838	$	(41	)	$	(684	)	$	(725	)
State and local	(14		)	2			(12		)	2		8			10		(8		)	(18		)	(26		)
Foreign	483			(104		)	379			91		(16		)	75		115			(102		)	13
Total	$	437		$	(61	)	$	376		$	95	$	828		$	923	$	66		$	(804	)	$	(738	)

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the federal statutory income tax rate applied to income (loss) from continuing operations before income taxes to the provision (benefit) for income taxes follows:

	Year Ended December 31,
(In millions)	2017			2016			2015
Total pre-tax income (loss) from continuing operations	$	(454	)	$	(1,164	)	$	(2,439	)
Total income tax expense (benefit)	$	376		$	923		$	(738	)
Effective income tax expense (benefit) rate on continuing operations	83		%	79		%	(30		)%
Income taxes at the statutory tax rate of 35% (a)	$	(159	)	$	(407	)	$	(854	)
Effects of foreign operations	140			47			(55		)
Adjustments to valuation allowances	446			1,270			95
State income taxes	(19		)	9			(15		)
Tax law change	(35		)	6			(3		)
Goodwill impairment	—			—			94
Other federal tax effects	3			(2		)	—
Income tax expense (benefit) on continuing operations	$	376		$	923		$	(738	)

Schedule of Deferred Tax Assets and Liabilities

Deferred tax assets and liabilities resulted from the following:

	Year Ended December 31,
(In millions)	2017			2016
Deferred tax assets:
Employee benefits	$	111		$	228
Operating loss carryforwards	1,030			1,065
Capital loss carryforwards	3			4
Foreign tax credits	611			4,430
Other credit carryforwards	—			35
Investments in subsidiaries and affiliates	174			91
Other	69			86
Subtotal	1,998			5,939
Valuation Allowance	(926		)	(4,301		)
Total deferred tax assets	1,072			1,638
Deferred tax liabilities:
Property, plant and equipment	1,332			3,672
Accrued revenue	81			75
Other	3			(7		)
Total deferred tax liabilities	1,416			3,740
Net deferred tax liabilities	$	344		$	2,102

Net Deferred Tax Assets Liabilities Table

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2017		2016
Assets:
Other noncurrent assets	$	489	$	336
Liabilities:
Noncurrent deferred tax liabilities	833		769
Noncurrent liabilities held for sale	—		1,669
Net deferred tax liabilities	$	344	$	2,102

Income Tax Returns Remaining Subject To Examination Table

As of December 31, 2017, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2008-2016
Equatorial Guinea	2007-2016
Libya	2012-2016
United Kingdom	2008-2016

^(a)  Includes federal and state jurisdictions.

Summary Of Activity In Unrecognized Tax Benefits Table

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2017			2016			2015
Beginning balance	$	66		$	65		$	80
Additions for tax positions of prior years	83			6			1
Reductions for tax positions of prior years	(3		)	(5		)	—
Settlements	(20		)	—			(7		)
Statute of limitations	—			—			(9		)
Ending balance	$	126		$	66		$	65

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Inventories (Tables)

12 Months Ended

Dec. 31, 2017

Inventory Disclosure [Abstract]

Schedule of Inventory, Current

	December 31,
(In millions)	2017		2016
Crude oil and natural gas	$	9	$	6
Supplies and other items	117		130
Inventories	$	126	$	136

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Schedule Of Property Plant And Equipment

Property, Plant and Equipment

	December 31,
(In millions)	2017		2016
United States E&P	$	15,867	$	14,158
International E&P	1,710		2,470
Corporate	88		99
Net property, plant and equipment	$	17,665	$	16,727

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year

At December 31, 2017, 2016 and 2015 we had total deferred exploratory well costs as follows:

	December 31,
(In millions)	2017			2016			2015
Amounts capitalized less than one year after completion of drilling	$	263		$	131		$	352
Amounts capitalized greater than one year after completion of drilling	32			118			85
Total deferred exploratory well costs	$	295		$	249		$	437
Number of projects with costs capitalized greater than one year after
completion of drilling	1			3			2
(In millions)	2017			2016			2015
Beginning balance	$	249		$	437		$	573
Additions	212			299			610
Charges to expense (a)	(64		)	(23		)	(111		)
Transfers to development	(102		)	(388		)	(635		)
Dispositions(b)	—			(76		)	—
Ending balance	$	295		$	249		$	437

^(a)  Includes $64 million in exploratory well costs being expensed as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon in August of 2017. See Note 10 for further detail.

^(b)  Includes sale of GOM assets in 2016.

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Impairment and Exploration Expenses (Tables)

12 Months Ended

Dec. 31, 2017

Impairments and Exploration Expenses [Abstract]

Details of Impairment of Long-Lived Assets Held and Used by Asset [Table Text Block]

The following table summarizes impairment charges of proved properties:

	Year Ended December 31,
(in millions)	2017		2016		2015
Total impairments	$	229	$	67	$	721

Exploration Expenses [Table Text Block]

The following table summarizes the components of exploration expenses:

	Year Ended December 31,
(In millions)	2017		2016		2015
Exploration Expenses
Unproved property impairments	$	246	$	195	$	655
Dry well costs	77		25		212
Geological and geophysical	25		5		31
Other	61		98		73
Total exploration expenses	$	409	$	323	$	971

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

Changes in asset retirement obligations were as follows:

	For Year Ended December 31,
(In millions)	2017			2016
Beginning balance	$	1,652		$	1,544
Incurred liabilities, including acquisitions	25			14
Settled liabilities, including dispositions	(50		)	(74		)
Accretion expense (included in depreciation, depletion and amortization)	85			79
Revisions of estimates	(227		)	96
Held for sale	(2		)	(7		)
Ending balance	$	1,483		$	1,652

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2017

Goodwill Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2017 and 2016:

(In millions)	U.S. E&P		Int'l E&P		Total
2016
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115
2017
Beginning balance, gross	$	—	$	115	$	115
Less: accumulated impairments	—		—		—
Beginning balance, net	—		115		115
Dispositions	—		—		—
Impairment	—		—		—
Ending balance, net	$	—	$	115	$	115

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives as they appear on the Balance Sheet

The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	December 31, 2017
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Not Designated as Hedges
Commodity	$	—	$	138	$	(138	)	Other current liabilities
Commodity	—		2		(2		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	140	$	(140	)
Total	$	—	$	140	$	(140	)

	December 31, 2016
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate	$	3	$	—	$	3		Other current assets
Interest rate	1		—		1			Other noncurrent assets
Cash Flow Hedges
Interest rate	$	64	$	—	$	64		Other noncurrent assets
Total Designated Hedges	$	68	$	—	$	68
Not Designated as Hedges
Commodity	$	—	$	60	$	(60	)	Other current liabilities
Total Not Designated as Hedges	$	—	$	60	$	(60	)
Total	$	68	$	60	$	8

Schedule of Interest Rate Derivatives

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”) based, floating rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	—	—	%	$	600	5.10	%
March 15, 2018	$	—	—	%	$	300	5.04	%

Effects of derivatives designated as fair value hedges

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income is summarized in the table below. There is no ineffectiveness related to the historical fair value hedges.

		Gain (Loss)
		Year Ended December 31,
(In millions)	Income Statement Location	2017		2016			2015
Derivative
Interest rate	Net interest and other	$	—	$	(4	)	$	—
Hedged Item
Debt	Net interest and other	$	—	$	4		$	—

Schedule of Interest Rate Swaps

The following table presents, by maturity date, information about our terminated forward starting interest rate swap agreements, including the rate.

	December 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR		Aggregate Notional Amount		Weighted Average, LIBOR
Maturity Dates	(in millions)		Fixed Rate		(in millions)		Fixed Rate
March 15, 2018	$	—	—	%	$	750	1.57	%

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest Rate Swaps
Beginning balance	$	60		$	—		$	—
Change in fair value recognized in other comprehensive income	(13		)	64			—
Reclassification from other comprehensive income	(47		)	(4		)	—
Ending balance	$	—		$	60		$	—

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table sets forth outstanding derivative contracts as of December 31, 2017 and the weighted average prices for those contracts:

Crude Oil
	2018				2019
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars (a)
Volume (Bbls/day)	85,000	85,000	85,000	85,000	10,000	10,000
Weighted average price per Bbl:
Ceiling	$56.38	$56.38	$56.96	$56.96	$60.00	$60.00
Floor	$51.65	$51.65	$51.53	$51.53	$55.00	$55.00
Sold put	$45.00	$45.00	$44.65	$44.65	$47.00	$47.00
Swaps
Volume (Bbls/day)	20,000	20,000	—	—	—	—
Weighted average price per Bbl	$55.12	$55.12	$—	$—	$—	$—
Basis Swaps (b)
Volume (Bbls/day)	5,000	5,000	10,000	10,000	—	—
Weighted average price per Bbl	$(0.60)	$(0.60)	$(0.67)	$(0.67)	$—	$—

^(a)  Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $63.51, a floor price of $57.00, and a sold put price of $50.00 and 20,000 Bbls/day of three-way collars for January - June 2019 with an average ceiling price of $67.92, a floor price of $53.50, and a sold put price of $46.50.

^(b)  The basis differential price is between WTI Midland and WTI Cushing.

Natural Gas
	2018
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	200,000	160,000	160,000	160,000
Weighted average price per MMBtu
Ceiling	$3.79	$3.61	$3.61	$3.61
Floor	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.50	$2.50	$2.50

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Fair Value Measurements Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables' present assets and liabilities accounted for at fair value on a recurring basis by hierarchy level.

	December 31, 2017
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	—			—			—		—
Derivative instruments, assets	$	—		$	—		$	—	$	—
Derivative instruments, liabilities
Commodity (a)	$	(20	)	$	(120	)	$	—	$	(140	)
Derivative instruments, liabilities	$	(20	)	$	(120	)	$	—	$	(140	)
	December 31, 2016
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	$	—		$	68		$	—	$	68
Derivative instruments, assets	$	—		$	68		$	—	$	68
Derivative instruments, liabilities
Commodity (a)	$	—		$	60		$	—	$	60
Derivative instruments, liabilities	$	—		$	60		$	—	$	60

^(a) Derivative instruments are recorded on a net basis in our balance sheet (see Note 13)

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2017				2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	179	$	229	$	15	$	67	$	56	$	386

Fair Value, by Balance Sheet Grouping

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2017 and 2016.

	December 31,
	2017				2016
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other current assets (a)	$	762	$	761	$	7	$	7
Other noncurrent assets	159		161		105		108
Total financial assets	$	921	$	922	$	112	$	115
Financial liabilities
Other current liabilities	$	32	$	43	$	68	$	75
Long-term debt, including current portion (b)	5,976		5,526		7,449		7,292
Deferred credits and other liabilities	110		103		114		107
Total financial liabilities	$	6,118	$	5,672	$	7,631	$	7,474

^(a)  Includes our two notes receivable relating to the sale of our Canadian business as of December 31, 2017, see note 5 for further information.

^(b)  Excludes capital leases, debt issuance costs and historical interest rate swap adjustments.

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Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt Instrument Table

The following table details our long-term debt:

	December 31,
(In millions)	2017			2016
Senior unsecured notes:
6.000% notes due 2017	—			682
5.900% notes due 2018	—			854
7.500% notes due 2019	—			228
2.700% notes due 2020(a)	600			600
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022 (b)	32			32
Series A notes due 2022 (b)	3			3
8.500% notes due 2023 (b)	70			70
8.125% notes due 2023 (b)	131			131
3.850% notes due 2025(a)	900			900
4.400% notes due 2027(a)	1,000			—
6.800% notes due 2032(a)	550			550
6.600% notes due 2037(a)	750			750
5.200% notes due 2045(a)	500			500
Capital leases:
Capital lease obligation expiring in 2018	—			1
Other obligations:
5.125% obligation relating to revenue bonds due 2037	—			1,000
Total(b)	5,536			7,301
Unamortized discount	(10		)	(9		)
Fair value adjustments(c)	—			7
Unamortized debt issuance cost	(32		)	(35		)
Amounts due within one year	—			(683		)
Total long-term debt	$	5,494		$	6,581

^(a)  These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2017 may be declared immediately due and payable.

^(c)  See Notes 13 and 14 for information on historical interest rate swaps.

Five Year Schedule Of Debt Payments Table

The following table shows future debt payments:

(In millions)
2018	$	—
2019	—
2020	600
2021	—
2022	1,035
Thereafter	3,901
Total long-term debt, including current portion	$	5,536

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Incentive Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2017

Incentive Based Compensation Plans [Abstract]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2017		2016		2015
Exercise price per share	$15.80		$7.22		$29.06
Expected annual dividend yield	1.3	%	2.8	%	2.9	%
Expected life in years	6.4		6.3		6.2
Expected volatility	42	%	36	%	32	%
Risk-free interest rate	2.1	%	1.4	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$6.07		$1.97		$6.84

Schedule of Share-based Compensation, Stock Options, Activity

The following is a summary of stock option award activity in 2017.

	Number	Weighted Average	Weighted Average Remaining	Aggregate Intrinsic Value
	of Shares	Exercise Price	Contractual Term	(in millions)
Outstanding at beginning of year	11,915,533	$27.71
Granted	799,591	$15.80
Exercised	(8,666)	$7.22
Canceled	(2,375,682)	$33.31
Outstanding at end of year	10,330,776	$25.52	4 years	$	13
Exercisable at end of year	8,661,893	$27.91	3 years	$	5
Expected to vest	1,650,737	$13.08	9 years	$	8

Schedule of Nonvested Restricted Stock Units Activity

The following is a summary of restricted stock and restricted stock unit award activity in 2017.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	6,933,533		$14.44
Granted	4,198,624		$16.13
Vested & Exercised	(2,472,367	)	$17.67
Canceled	(1,086,945	)	$15.03
Unvested at end of year	7,572,845		$14.24

Schedule of Performance Units, Valuation [Table Text Block]

The key assumptions used in the Monte Carlo simulation to determine the fair value of stock-based performance units granted in 2017, 2016 and 2015 were:

	2017		2016		2015 (a)
Valuation date stock price	$16.93		$16.93		$16.93
Expected annual dividend yield	1.2	%	1.2	%	1.2	%
Expected volatility	54	%	34	%	33	%
Risk-free interest rate	1.9	%	1.7	%	1.4	%
Fair value of stock-based performance units outstanding	$21.63		$19.86		$0.00

^(a) As of December 31, 2017, there were no 2015 performance unit awards outstanding.

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Tables)

12 Months Ended

Dec. 31, 2017

Defined Benefit Plan [Abstract]

Summary Of Defined Benefit Pension Plans With Accumulated Benefit Obligations

Obligations and funded status– The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.    

	Pension Benefits												Other Benefits
	2017						2016						2017			2016
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			U.S.
Accumulated benefit obligation	378			599			386			583			221			227
Change in benefit obligations:
Beginning balance	$	397		$	583		$	525		$	579		$	227		$	260
Service cost	22			—			25			—			2			2
Interest cost	13			17			16			23			8			11
Plan amendment	—			—			—			1			—			(38		)
Actuarial loss (gain)	42			(7		)	78			139			5			11
Foreign currency exchange rate changes	—			52			—			(108		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(19		)
Ending balance	$	384		$	599		$	397		$	583		$	221		$	227
Change in fair value of plan assets:
Beginning balance	$	227		$	595		$	354		$	608		$	—		$	—
Actual return on plan assets	27			47			25			129			—			—
Employer contributions	52			17			95			18			21			20
Foreign currency exchange rate changes	—			57			—			(109		)	—			—
Divestiture	—			—			—			—			—			—
Settlements paid	(84		)	(31		)	(240		)	(36		)	—			—
Benefits paid	(6		)	(15		)	(7		)	(15		)	(21		)	(20		)
Ending balance	$	216		$	670		$	227		$	595		$	—		$	—
Funded status of plans at December 31	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	—			71			—			12			—			—
Current liabilities	(6		)	—			(4		)	—			(21		)	(21		)
Noncurrent liabilities	(162		)	—			(166		)	—			(200		)	(206		)
Accrued benefit cost	$	(168	)	$	71		$	(170	)	$	12		$	(221	)	$	(227	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	122		$	58		$	130		$	81		$	30		$	25
Prior service cost (credit)	(45		)	3			(55		)	4			(56		)	(63		)

Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income

Components of net periodic benefit cost from continuing operations and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits																		Other Benefits
	Year Ended December 31,																		Year Ended December 31,
	2017						2016						2015						2017			2016			2015
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			U.S.			U.S.			U.S.
Components of net periodic benefit cost:
Service cost	$	22		$	—		$	25		$	—		$	29		$	14		$	2		$	2		$	3
Interest cost	13			17			16			23			25			25			8			11			11
Expected return on plan assets	(13		)	(30		)	(18		)	(35		)	(30		)	(37		)	—			—			—
Amortization:
- prior service cost (credit)	(10		)	—			(10		)	1			(7		)	1			(7		)	(3		)	(4		)
- actuarial loss	8			1			14			—			22			2			—			—			1
Net curtailment loss (gain)(a)	—			—			—			—			(5		)	4			—			—			(7		)
Net settlement loss(b)	28			4			97			6			119			—			—			—			—
Net periodic benefit cost(c)	$	48		$	(8	)	$	124		$	(5	)	$	153		$	9		$	3		$	10		$	4
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	28		$	(26	)	$	70		$	41		$	30		$	(25	)	$	5		$	11		$	(21	)
Amortization of actuarial gain (loss)	(36		)	(4		)	(111		)	(6		)	(134		)	(2		)	—			—			(1		)
Prior service cost (credit)	—			—			—			1			(89		)	1			—			(38		)	—
Amortization of prior service credit (cost)	10			—			10			(1		)	7			(5		)	7			3			13
Total recognized in other comprehensive (income) loss	$	2		$	(30	)	$	(31	)	$	35		$	(186	)	$	(31	)	$	12		$	(24	)	$	(9	)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	50		$	(38	)	$	93		$	30		$	(33	)	$	(22	)	$	15		$	(14	)	$	(5	)

^(a)  Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.

^(b)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.

^(c)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

Schedule of Assumptions Used

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2017, 2016 and 2015.

	Pension Benefits												Other Benefits
	2017				2016				2015				2017		2016		2015
(In millions)	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		U.S.		U.S.
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.55	%	2.50	%	4.02	%	2.70	%	4.04	%	3.90	%	3.54	%	3.98	%	4.36	%
Rate of compensation increase (a)	4.00	%	—		4.00	%	—		4.00	%	—		4.00	%	4.00	%	4.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.86	%	2.70	%	3.66	%	3.90	%	3.79	%	3.70	%	3.98	%	4.36	%	3.93	%
Expected long-term return on plan assets	6.50	%	4.50	%	6.75	%	5.50	%	6.75	%	5.70	%	—		—		—
Rate of compensation increase (a)	4.00	%	—		4.00	%	—	%	4.00	%	3.60	%	4.00	%	4.00	%	4.00	%

^(a)  No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.

Schedule of Health Care Cost Trend Rates

Assumed weighted average health care cost trend rates

	2017		2016		2015
Initial health care trend rate	8.00	%	8.25	%	8.00	%
Ultimate trend rate	4.70	%	4.50	%	4.50	%
Year ultimate trend rate is reached	2025		2025		2024

Fair Value of Defined Benefit Pension Plans Assets

The following tables present the fair values of our defined benefit pension plan's assets, by level within the fair value hierarchy, as of December 31, 2017 and 2016.

	December 31, 2017
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	6	$	1	$	—	$	—	$	—	$	—	$	6	$	1
Equity securities:
Common stock	81		—		—		—		—		—		81		—
Private equity	—		—		—		—		16		—		16		—
Mutual and pooled funds	—		151		—		115		—		—		—		266
Fixed income securities:
Corporate	—		—		6		—		—		—		6		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	19		—		2		—		3		—		24		—
Pooled funds	—		—		—		403		—		—		—		403
Other	—		—		—		—		19		—		19		—
Total investments, at fair value	111		152		8		518		38		—		157		670
Commingled funds (a)	—		—		—		—		—		—		59		—
Total investments	$	111	$	152	$	8	$	518	$	38	$	—	$	216	$	670

	December 31, 2016
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	8	$	5	$	—	$	—	$	—	$	—	$	8	$	5
Equity securities:
Common stock	82		—		—		—		—		—		82		—
Private equity	—		—		—		—		20		—		20		—
Mutual and pooled funds	—		201		—		159		—		—		—		360
Fixed income securities:
Corporate	—		—		52		—		—		—		52		—
Exchange traded funds	5		—		—		—		—		—		5		—
Government	6		—		19		—		—		—		25		—
Pooled funds	—		—		—		230		—		—		—		230
Other	—		—		—		—		21		—		21		—
Total investments, at fair value	101		206		71		389		41		—		213		595
Commingled funds (a)	—		—		—		—		—		—		14		—
Total investments	$	101	$	206	$	71	$	389	$	41	$	—	$	227	$	595

^(a) After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update.

Schedule of Expected Benefit Payments

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2017 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l		U.S.
2018	$	43	$	17	$	21
2019	40		18		20
2020	37		17		20
2021	33		19		19
2022	30		21		18
2023 through 2027	123		118		74

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Reclassifications Out of Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2017

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassification out of AOCI [Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:

	Year Ended December 31,
(In millions)	2017			2016			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(9	)	$	(14	)	General and administrative
Net settlement loss	(32		)	(103		)	General and administrative
Derivative hedges
Recognized gain on terminated derivative hedge	46			—			Net interest and other
Ineffective portion of derivative hedge	1			4			Net interest and other
	6			(113		)	Income (loss) from operations
	(40		)	41			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	$	(34	)	$	(72	)	Income (loss) from continuing operations
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	(30		)	—			Income (loss) from discontinued operations
Total reclassifications to expense	$	(64	)	$	(72	)

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

	Year Ended December 31,
(In millions)	2017			2016			2015
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(379	)	$	(375	)	$	(325	)
Income taxes paid to taxing authorities  (a)	(391		)	(84		)	(171		)
Noncash investing activities, related to continuing operations:
Changes in asset retirement costs	$	(202	)	$	110		$	(95	)
Asset retirement obligations assumed by buyer	14			40			251
Increase in capital expenditure accrual	176			—			—
Notes receivable for disposition of assets	748			—			—

^(a) Includes a payment of $108 million made to U.K. taxing authorities to preserve our appeal rights, see Note 7 - Income Taxes for additional discussion.

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Other Items (Tables)

12 Months Ended

Dec. 31, 2017

Interest and Other Income [Abstract]

Schedule Of Net Interest And Other Financing Table

Net interest and other

	Year Ended December 31,
(In millions)	2017			2016			2015
Interest:
Interest income	$	34		$	14		$	9
Interest expense	(380		)	(398		)	(350		)
Income on interest rate swaps	53			13			11
Interest capitalized	3			18			19
Total interest	(290		)	(353		)	(311		)
Other:
Net foreign currency gain (loss)	8			6			4
Other	12			15			21
Total other	20			21			25
Net interest and other	$	(270	)	$	(332	)	$	(286	)

Schedule Of Foreign Currency Transactions Table

Foreign currency – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

	Year Ended December 31,
(In millions)	2017		2016			2015
Net interest and other	$	8	$	6		$	4
Provision for income taxes	57		(32		)	(11		)
Aggregate foreign currency gains (losses)	$	65	$	(26	)	$	(7	)

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Equity Method Investments and Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments Disclosure [Abstract]

Schedule of Equity Method Investments

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2017	2017		2016
EGHoldings	60%	$	456	$	550
Alba Plant LLC	52%	214		215
AMPCO	45%	177		165
Other investments		—		1
Total		$	847	$	931

Income And Balance Sheet Information of Equity Investees Table

Summarized financial information for equity method investees is as follows:

(In millions)	2017		2016		2015
Income data – year (a):
Revenues and other income	$	1,294	$	770	$	769
Income from operations	631		346		313
Net income	508		313		280
Balance sheet data – December 31:
Current assets	$	586	$	525
Noncurrent assets	1,044		1,173
Current liabilities	221		218
Noncurrent liabilities	94		47

^(a)  See Item 15 Exhibits, Financial Statement Schedules which contains the Alba Plant LLC audited financial statements, which have been included pursuant to Rule 3-09 of Regulation S-X.

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Leases (Tables)

12 Months Ended

Dec. 31, 2017

Leases [Abstract]

Future Minimum Commitments For Capital And Operating Leases Table

Future minimum commitments for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Operating Lease Obligations
2018	$	29
2019	28
2020	27
2021	26
2022	5
Later years	4
Sublease rentals	—
Total minimum lease payments	$	119

^* Future minimum commitments for capital lease obligations are nil as of December 31, 2017.

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Summary of Principal Accounting Policies DDA (Details)	12 Months Ended
	Dec. 31, 2017
Office furniture, equipment and computer hardwareWells and Related Equipment and Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	4 years
Office furniture, equipment and computer hardwareWells and Related Equipment and Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	15 years
Pipelines [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Pipelines [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Plants, facilities, mine equipment and infrastructure [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Plants, facilities, mine equipment and infrastructure [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years

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Accounting Standards Accounting Standards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Marketing Revenues (Expense) [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gross Billings	$ 130	$ 100

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Income per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Income (loss) from continuing operations	$ (830)	$ (2,087)	$ (1,701)
Income (loss) from discontinued operations	(4,893)	(53)	(503)
Net income (loss)	$ (5,723)	$ (2,140)	$ (2,204)
Weighted average common shares outstanding, basic	850	819	677
Weighted average common shares outstanding, diluted	850	819	677
Basic:
Income from continuing operations (in dollars per basic share)	$ (0.97)	$ (2.55)	$ (2.51)
Discontinued operations (in dollars per basic share)	(5.76)	(0.06)	(0.75)
Net income (in dollars per basic share)	(6.73)	(2.61)	(3.26)
Diluted:
Income from continuing operations (in dollars per diluted share)	(0.97)	(2.55)	(2.51)
Discontinued operations (in dollars per diluted share)	(5.76)	(0.06)	(0.75)
Net income (in dollars per diluted share)	$ (6.73)	$ (2.61)	$ (3.26)
Antidilutive securities excluded from computation of earnings per share	11	13	13

XML

Acquisitions Acquisitions Asset (Details) a in Thousands, Boe in Thousands, $ in Millions				3 Months Ended		12 Months Ended
	Jun. 01, 2017 USD ($) a	May 01, 2017 USD ($) a Boe	Aug. 01, 2016 USD ($) a	Dec. 31, 2017 USD ($)	Jun. 30, 2017 a	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Business Combination, Consideration Transferred | $			$ 904
Payments to Acquire Businesses, Net of Cash Acquired | $						$ 1,891	$ 902	$ 0
Permian Basin [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a					91
Payments to Acquire Businesses, Net of Cash Acquired | $				$ 63
Permian Basin [Member] | BC Operating Transaction [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a		70
Production, Barrels of Oil Equivalents | Boe		5
Payments to Acquire Businesses, Net of Cash Acquired | $		$ 1,100
Permian Basin [Member] | Black Mountain Oil and Gas Transaction [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a	21
Payments to Acquire Businesses, Net of Cash Acquired | $	$ 700
Northern Delaware - Permian Basin [Member] | BC Operating Transaction [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a					70
Anadarko Basin STACK Play [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a			61

XML

Dispositions (Details)		1 Months Ended					2 Months Ended	3 Months Ended											12 Months Ended
	May 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Nov. 30, 2016 USD ($)	Oct. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Aug. 31, 2015 USD ($)	Apr. 30, 2016 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2017 USD ($) notes_receivable	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment																			$ 1,787,000,000	$ 1,219,000,000	$ 225,000,000
Impairment of Oil and Gas Properties																			229,000,000	67,000,000	721,000,000
Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Impairment of Oil and Gas Properties											$ 6,600,000,000								6,636,000,000	0	31,000,000
Net gain (loss) on disposal of assets																			(43,000,000)	0	0
GOM Producing Properties [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					$ 111,000,000
Neptune Field [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment															$ 4,000,000
East Texas/North Louisiana and Wilburton Assets [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						$ 100,000,000
Net gain (loss) on disposal of assets						$ (1,000,000)
Kenya and Ethiopia Assets [Member]
Dispositions Detail [Line Items]
Net gain (loss) on disposal of assets																	$ (109,000,000)
Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Impairment of Oil and Gas Properties											$ 4,960,000,000
East Texas/North Louisiana and Wilburton Assets [Member]
Dispositions Detail [Line Items]
Impairment of Oil and Gas Properties																					44,000,000
Fair Value, Measurements, Nonrecurring [Member]
Dispositions Detail [Line Items]
Impairment of Oil and Gas Properties																			$ 229,000,000
Assets, Fair Value Adjustment																				67,000,000	$ 386,000,000
Fair Value, Measurements, Nonrecurring [Member] | East Texas/North Louisiana and Wilburton Assets [Member] | Fair Value, Inputs, Level 3 [Member]
Dispositions Detail [Line Items]
Assets, Fair Value Adjustment																		$ (44,000,000)
Discontinued Operations, Disposed of by Sale [Member] | Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 2,500,000,000
Number of notes receivable	2																		2
Net gain (loss) on disposal of assets										$ (43,000,000)
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Oklahoma Resource Basin [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		$ 25,000,000
Net gain (loss) on disposal of assets		$ 21,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | West Texas and New Mexico [Domain]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				$ 235,000,000									$ 67,000,000
Net gain (loss) on disposal of assets				$ 63,000,000									$ 55,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Wyoming Upstream and Midstream Assets Sold [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 155,000,000											$ 690,000,000
Net gain (loss) on disposal of assets												$ 38,000,000		$ 266,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Shenandoah in Gulf of Mexico, Piceance in Colorado, and West Texas [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment							$ 80,000,000
Net gain (loss) on disposal of assets																			$ 32,000,000	$ (48,000,000)
Working capital interest to be disposed of							10.00%
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | GOM Producing Properties [Member]
Dispositions Detail [Line Items]
Net gain (loss) on disposal of assets																$ 228,000,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Non-core [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment									$ 53,000,000
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-core [Member]
Dispositions Detail [Line Items]
Assets held for sale																			66,000,000
Liabilities held for sale																			$ 2,000,000
Variable Interest Entity, Not Primary Beneficiary [Member] | Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage																			20.00%
Note Receivable 1 [Member] | Discontinued Operations, Disposed of by Sale [Member] | Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Accounts, Notes, Loans and Financing Receivable, Net, Current	$ 375,000,000
Subsequent Event [Member] | Discontinued Operations, Disposed of by Sale [Member] | Oil Sands Mining Segment [Member]
Dispositions Detail [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment								$ 1,800,000,000

XML

Dispositions Discontinued Operations - Reported in Consolidated Statements of Income (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Impairments			$ 229	$ 67	$ 721
Oil Sands Mining Segment [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total sales and other revenues and other income			431	863	908
Net gain (loss) on disposal of assets			(43)	0	0
Total revenues and other income			388	863	908
Production expenses			254	601	715
Exploration expenses			0	7	347
Depreciation, depletion and amortization			40	239	236
Impairments		$ 6,600	6,636	0	31
Other			25	87	98
Total costs and expenses			6,955	934	1,427
Pretax income (loss) from discontinued operations			(6,567)	(71)	(519)
Provision (benefit) for income taxes			(1,674)	(18)	(16)
Income (loss) from discontinued operations			$ (4,893)	$ (53)	$ (503)
Discontinued Operations, Disposed of by Sale [Member] | Oil Sands Mining Segment [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Net gain (loss) on disposal of assets	$ (43)

XML

Dispositions Discontinued Operations - Reflected as Held-For-Sale in Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Total current assets held for sale	$ 11	$ 227
Total current assets held for sale—continuing operations	11	1
Noncurrent assets:
Other	55	9,098
Current liabilities:
Total current liabilities held for sale	0	121
Total current liabilities held for sale—continuing operations	0	0
Discontinued Operations, Held-for-sale [Member]
Noncurrent liabilities:
Total noncurrent liabilities held for sale	2	1,791
Oil Sands Mining Segment [Member] | Discontinued Operations, Held-for-sale [Member]
Current assets:
Cash and cash equivalents	0	2
Accounts receivables	0	129
Inventories	0	91
Other	0	4
Total current assets held for sale	0	226
Noncurrent assets:
Property, plant and equipment, net	0	8,991
Other	0	106
Total noncurrent assets held for sale—discontinued operations	0	9,097
Total noncurrent assets held for sale—continuing operations	55	1
Total noncurrent assets held for sale	55	9,098
Current liabilities:
Accounts payable	0	111
Other	0	10
Total current liabilities held for sale	0	121
Noncurrent liabilities:
Asset retirement obligations	0	95
Deferred tax liabilities	0	1,669
Other	0	20
Total noncurrent liabilities held for sale—discontinued operations	0	1,784
Total noncurrent liabilities held for sale—continuing operations	$ 2	$ 7

XML

Segment Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) segment	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment	2
Sales and other operating revenues	$ 4,211	$ 2,930	$ 4,136
Marketing revenues	162	240	499
Total revenues	4,373	3,170	4,635
Income from equity method investments	256	175	145
Net gain (loss) on disposal of assets and other income	136	442	173
Production expenses	706	712	979
Marketing costs	168	245	500
Other Cost and Expense, Operating	431	484	410
Exploration expenses	409	323	971
Depreciation, depletion and amortization	2,372	2,156	2,721
Impairment of Oil and Gas Properties	229	67	721
Taxes other than income	183	151	216
General and Administrative Expense	400	481	588
Net interest and other	270	332	286
Gain (Loss) on Extinguishment of Debt	(51)	0	0
Provision for income taxes	376	923	(738)
Income from continuing operations	(830)	(2,087)	(1,701)
Property, Plant and Equipment, Additions	2,150	1,036	2,946
Derivative, Gain (Loss) on Derivative, Net	(36)	(66)	128
Deferred Foreign Income Tax Expense (Benefit)	(104)	(16)	(102)
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Severance Costs		8	55
Valuation Allowances and Reserves, Period Increase (Decrease)		1,346
Loss on Contract Termination		113
Pension Plan [Member]
Segment Reporting Information [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(32)	(103)	(119)
Net Interest and Other [Member] | Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Segment Reporting Information [Line Items]
Derivative, Gain (Loss) on Derivative, Net	47
Operating Segments [Member] | United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	3,138	2,375	3,358
Marketing revenues	29	135	396
Total revenues	3,167	2,510	3,754
Income from equity method investments	0	0	0
Net gain (loss) on disposal of assets and other income	13	28	24
Production expenses	476	486	724
Marketing costs	36	142	401
Other Cost and Expense, Operating	354	328	335
Exploration expenses	154	127	314
Depreciation, depletion and amortization	2,011	1,835	2,377
Impairment of Oil and Gas Properties	4	20	2
Taxes other than income	173	149	215
General and Administrative Expense	119	94	127
Net interest and other	0	0	0
Gain (Loss) on Extinguishment of Debt	0
Provision for income taxes	1	(228)	(265)
Income from continuing operations	(148)	(415)	(452)
Property, Plant and Equipment, Additions	2,081	936	2,553
Operating Segments [Member] | International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,154	665	728
Marketing revenues	133	105	103
Total revenues	1,287	770	831
Income from equity method investments	256	175	157
Net gain (loss) on disposal of assets and other income	6	32	27
Production expenses	229	226	255
Marketing costs	132	103	99
Other Cost and Expense, Operating	77	43	48
Exploration expenses	5	17	101
Depreciation, depletion and amortization	328	276	295
Impairment of Oil and Gas Properties	0	0	0
Taxes other than income	0	0	0
General and Administrative Expense	32	35	44
Net interest and other	0	0	0
Gain (Loss) on Extinguishment of Debt	0
Provision for income taxes	372	49	61
Income from continuing operations	374	228	112
Property, Plant and Equipment, Additions	42	82	368
Not Allocated to Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	(81)	(110)	50
Marketing revenues	0	0	0
Total revenues	(81)	(110)	50
Income from equity method investments	0	0	(12)
Net gain (loss) on disposal of assets and other income	117	382	122
Production expenses	1	0	0
Marketing costs	0	0	0
Other Cost and Expense, Operating	0	113	27
Exploration expenses	250	179	556
Depreciation, depletion and amortization	33	45	49
Impairment of Oil and Gas Properties	225	47	719
Taxes other than income	10	2	1
General and Administrative Expense	249	352	417
Net interest and other	270	332	286
Gain (Loss) on Extinguishment of Debt	(51)
Provision for income taxes	3	1,102	(534)
Income from continuing operations	(1,056)	(1,900)	(1,361)
Property, Plant and Equipment, Additions	$ 27	$ 18	$ 25

XML

Segment Information (Geographical)(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	$ 4,373	$ 3,170	$ 4,635
Long-Lived Assets	18,512	17,658
UNITED STATES
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	3,086	2,400	3,804
Long-Lived Assets	15,971	14,272
EQUATORIAL GUINEA
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	530	444	444
Long-Lived Assets	1,582	1,794
LIBYAN ARAB JAMAHIRIYA
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	431	54	0
UNITED KINGDOM
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	289	263	380
Other International [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	37	9	$ 7
Long-Lived Assets	$ 959	$ 1,592

XML

Segment Information (Products and Services)(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue from External Customer by Product Line [Line Items]
Revenue, Net	$ 4,373	$ 3,170	$ 4,635
Crude oil and condensate [Member]
Revenue from External Customer by Product Line [Line Items]
Revenue, Net	3,477	2,605	3,963
Natural Gas Liquids [Member]
Revenue from External Customer by Product Line [Line Items]
Revenue, Net	338	198	203
Natural gas [Member]
Revenue from External Customer by Product Line [Line Items]
Revenue, Net	510	356	464
Miscellaneous other [Member]
Revenue from External Customer by Product Line [Line Items]
Revenue, Net	$ 48	$ 11	$ 5

XML

Segment Information (Narrative)(Details) - Sales Revenue, Net [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Vitol [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Concentration Risk, Percentage	10.00%
Valero Marketing and Supply [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Concentration Risk, Percentage		13.00%
Tesoro Petroleum [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Concentration Risk, Percentage		11.00%
Flint Hills Resources [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Concentration Risk, Percentage		10.00%
Shell Oil [Member]
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Concentration Risk, Percentage			10.00%

XML

Income Taxes (Schedule of Income (Loss) Before Tax Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
United States	$ (783)	$ (1,449)	$ (2,384)
Foreign	329	285	(55)
Income from continuing operations before income taxes	$ (454)	$ (1,164)	$ (2,439)

XML

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	$ (454)	$ (1,164)	$ (2,439)
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	(159)	(407)	(854)
Effective Income Tax Rate Reconciliation, Foreign Income Tax Rate Differential, Amount	140	47	(55)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	446	1,270	95
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	(19)	9	(15)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	(35)	6	(3)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Impairment Losses, Amount	0	0	94
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	3	(2)	0
Income Tax Expense (Benefit)	$ 376	$ 923	$ (738)
Libya Statutory Income Tax Rate	93.50%
Effective income tax rate excluding Libya	5.00%	79.00%	29.00%
Federal
Current	$ (32)	$ 2	$ (41)
Deferred	41	836	(684)
Total	9	838	(725)
State and local
Current	(14)	2	(8)
Deferred	2	8	(18)
Total	(12)	10	(26)
Foreign
Current	483	91	115
Deferred	(104)	(16)	(102)
Total	379	75	13
Current Income Tax Expense (Benefit)	437	95	66
Deferred Income Tax Expense (Benefit)	$ (61)	$ 828	$ (804)
Effective Tax Rate Reconciliation [Abstract]
Effective income tax rate on continuing operations	83.00%	79.00%	(30.00%)

XML

Income Taxes Income Taxes (Schedule of Net Deferred Tax Asset/Liability) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, Gross [Abstract]
Employee benefits	$ 111	$ 228
Operating loss carryforwards	1,030	1,065
Capital loss carryforwards	3	4
Foreign tax credits	611	4,430
Other credit carryforwards	0	35
Investments in subsidiaries and affiliates	174	91
Other	69	86
Deferred Tax Assets, Gross	1,998	5,939
Deferred Tax Assets, Valuation Allowance	(926)	(4,301)
Deferred Tax Assets, Net of Valuation Allowance	1,072	1,638
Deferred Tax Liabilities, Gross [Abstract]
Property, plant and equipment	1,332	3,672
Accrued revenue	81	75
Other	3	(7)
Deferred Tax Liabilities, Gross	1,416	3,740
Deferred Tax Liabilities, Net	$ 344	$ 2,102

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Income Taxes (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Reduction in valuation allowance as a result of U.S. Tax Reform	$ 3,819
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	13
Valuation and Qualifying Accounts Disclosure [Line Items]
Increase in Unrecognized Tax Benefits is Reasonably Possible	83
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	446	$ 1,270	$ 95
Income tax benefit due to tax law change	35
Impairments and Exploration Expenses [Abstract]
Deferred Tax Liabilities, Net	344	2,102
Deferred Tax Assets, Valuation Allowance	926	4,301
Assets
Other noncurrent assets	489	336
Liabilities
Noncurrent deferred tax liabilities	833	769
Domestic Tax Authority [Member]
Impairments and Exploration Expenses [Abstract]
Deferred Tax Assets, Valuation Allowance	41
UNITED STATES
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	898
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	119
Internal Revenue Service (IRS) [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Additions for Charges to Cost and Expense	926	1,268	$ 99
UK Government [Member] | Foreign Tax Authority [Member]
Impairments and Exploration Expenses [Abstract]
Income Tax Examination, Penalties and Interest Expense	108
Discontinued Operations, Held-for-sale [Member] | Oil Sands Mining Segment [Member]
Liabilities
Noncurrent liabilities held for sale	$ 0	$ 1,669

XML

Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unrecognized Tax Benefit Rollforward [Abstract]
Unrecognized Tax Benefits, Beginning Balance	$ 66	$ 65	$ 80
Additions for tax positions of prior years	83	6	1
Reductions for tax positions of prior years	(3)	(5)	0
Settlements	(20)	0	(7)
Statute of limitations	0	0	(9)
Unrecognized Tax Benefits, Ending Balance	126	66	65
Unrecognized Tax Benefits That Would Impact Effective Tax Rate	10
Increase in Unrecognized Tax Benefits is Reasonably Possible	83
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	2	1	$ 1
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 25	$ 15

XML

Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Crude oil and natural gas	$ 9	$ 6
Supplies and sundry items	117	130
Inventories at cost	$ 126	$ 136

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 17,665	$ 16,727
United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	15,867	14,158
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	1,710	2,470
Corporate [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 88	$ 99

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Property, Plant and Equipment (Details 2) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($) project	Dec. 31, 2016 USD ($) project	Dec. 31, 2015 USD ($) project
Property, Plant and Equipment [Abstract]
Amounts capitalized less than one year after completion of drilling				$ 263	$ 131	$ 352
Amounts capitalized greater than one year after completion of drilling				32	118	85
Total deferred exploratory well costs	$ 249	$ 437	$ 573	$ 295	$ 249	$ 437
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | project				1	3	2
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	249	437	573
Additions	212	299	610
Charges to expense	(64)	(23)	(111)
Transfers to development	(102)	(388)	(635)
Dispositions	0	(76)	0
Ending balance	$ 295	$ 249	$ 437

XML

Property, Plant and Equipment (Details 3) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) project	Dec. 31, 2016 USD ($) project	Dec. 31, 2015 USD ($) project
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Cost, Charged to Expense	$ 64	$ 23	$ 111
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects | project	1	3	2
Amounts capitalized greater than one year after completion of drilling	$ 32	$ 118	$ 85
Diaba [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized Exploratory Well Cost, Charged to Expense	$ 64

XML

Impairment and Exploration Expenses Impairments (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			$ 229	$ 67	$ 721
Goodwill, Impairment Loss			0	0
Oklahoma and Gulf of Mexico [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties				67
East Texas/North Louisiana and Wilburton Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties					44
Colorado and Gulf of Mexico [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties					335
United States Exploration and Production [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, Impairment Loss			0	0	340
Oil Sands Mining Segment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		$ 6,600	6,636	$ 0	$ 31
Fair Value, Measurements, Nonrecurring [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties			229
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | International Exploration and Production [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties	$ 136		136
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Gulf of Mexico Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Expense - Proved Properties	$ 65		$ 89

XML

Impairment and Exploration Expenses Exploration Expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Exploration Expenses [Line Items]
Exploration expenses	$ 409	$ 323	$ 971
Exploration Abandonment and Impairment Expense	323	220	867
Capitalized Exploratory Well Cost, Charged to Expense	64	23	111
Unproved Property Impairments [Member]
Exploration Expenses [Line Items]
Exploration expenses	246	195	655
Dry Well Costs [Member]
Exploration Expenses [Line Items]
Exploration expenses	77	25	212
Geological and Geophysical [Member]
Exploration Expenses [Line Items]
Exploration expenses	25	5	31
Other Exploration Expenses [Member]
Exploration Expenses [Line Items]
Exploration expenses	61	$ 98	$ 73
Tchicuate [Member] | Unproved Property Impairments [Member]
Exploration Expenses [Line Items]
Exploration Abandonment and Impairment Expense	43
Diaba [Member]
Exploration Expenses [Line Items]
Capitalized Exploratory Well Cost, Charged to Expense	64
Diaba [Member] | Unproved Property Impairments [Member]
Exploration Expenses [Line Items]
Exploration expenses	159
Exploration Abandonment and Impairment Expense	$ 95

XML

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation Beginning Balance	$ 1,652	$ 1,544
Incurred, including acquisitions	25	14
Settled, including dispositions	(50)	(74)
Accretion expense (included in depreciation, depletion and amortization)	85	79
Revisions to previous estimates	(227)	96
Held for sale	(2)	(7)
Asset Retirement Obligation Ending Balance	1,483	1,652
Asset Retirement Obligation, Current	$ 55	$ 50

XML

Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Goodwill [Line Items]
Goodwill, gross		$ 115	$ 115
Less: accumulated impairment		0	0
Goodwill [Roll Forward]
Beginning balance, net	$ 115	115
Dispositions	0	0
Impairment	0	0
Ending balance, net	115	115	115
United States Exploration and Production [Member]
Goodwill [Line Items]
Goodwill, gross		0	0
Less: accumulated impairment		0	0
Goodwill [Roll Forward]
Beginning balance, net	0	0
Dispositions	0	0
Impairment	0	0	340
Ending balance, net	0	0	0
International Exploration and Production [Member]
Goodwill [Line Items]
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				40.00%
Goodwill, gross		115	115
Less: accumulated impairment		0	0
Goodwill [Roll Forward]
Beginning balance, net	115	115
Dispositions	0	0
Impairment	0	0
Ending balance, net	$ 115	$ 115	$ 115

XML

Derivatives (Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 68
Derivative Asset, Fair Value, Gross Liability		60
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		8
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Instruments in Hedges, Assets, at Fair Value		68
Derivative Instruments in Hedges, Liabilities, at Fair Value		0
Derivative Instruments in Hedges, at Fair Value, Net		68
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 0	0
Derivative Asset, Fair Value, Gross Liability	140	60
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(140)	(60)
Derivative Liability, Fair Value, Gross Liability	140
Other Current Assets [Member] | Interest rate [Member] | Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		3
Other Noncurrent Assets [Member] | Interest rate [Member] | Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		1
Other Noncurrent Assets [Member] | Interest rate [Member] | Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		64
Interest Rate Cash Flow Hedge Asset at Fair Value		64
Interest Rate Cash Flow Hedge Liability at Fair Value		0
Other Current Liabilities [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	138	60
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(138)	$ (60)
Other Noncurrent Liabilities [Member] | Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Asset, Fair Value, Gross Liability	2
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (2)

XML

Derivatives (Fair Value Hedges) (Details) - Interest Rate Contract [Member] - Fair Value Hedging [Member] - Designated as Hedging Instrument [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debentures Due 2017 [Member]
Derivatives, Fair Value [Line Items]
Aggregate Notional Amount	$ 0	$ 600
Weighted-average, LIBOR-based, floating rate	0.00%	5.10%
Notes Due 2018 [Member]
Derivatives, Fair Value [Line Items]
Aggregate Notional Amount	$ 0	$ 300
Weighted-average, LIBOR-based, floating rate	0.00%	5.04%

XML

Derivatives (Fair Value Hedges IS & OCI) (Details) - Net interest and other [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	$ 0	$ 4	$ 0
Interest rate [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Unrealized Gain (Loss) on Fair Value Hedging Instruments	$ 0	$ (4)	$ 0

XML

Derivatives Derivatives (Schedule of Cash Flow Hedges Rollforward) (Details) - Interest Rate Swap [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net	$ 0	$ 60	$ 0	$ 0
Change in fair value recognized in other comprehensive income	(13)	64	0
Reclassification from other comprehensive income	(47)	(4)	$ 0
Notes Due 2018 [Member]
Derivatives, Fair Value [Line Items]
Aggregate Notional Amount - Interest Rate Swap Agreements	$ 0	$ 750
Derivative, Fixed Interest Rate	0.00%	1.57%

XML

Derivatives (Non Hedges Commodity) (Details)	Feb. 12, 2018 Bbls_per_day $ / bbl	Dec. 31, 2017 MMBTU MMBTU_per_day BBL / Days Bbls_per_day $ / MMBTU $ / bbl
Crude Oil Three-Way Collars for the First Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		85,000
Derivative, Average Cap Price		56.38
Derivative, Average Floor Price		51.65
Derivatives, Average Sold Put Price		45.00
Crude Oil Three-Way Collars for the Second Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		85,000
Derivative, Average Cap Price		56.38
Derivative, Average Floor Price		51.65
Derivatives, Average Sold Put Price		45.00
Crude Oil Three-Way Collars for Third Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		85,000
Derivative, Average Cap Price		56.96
Derivative, Average Floor Price		51.53
Derivatives, Average Sold Put Price		44.65
Crude Oil Three-Way Collars for the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		85,000
Derivative, Average Cap Price		56.96
Derivative, Average Floor Price		51.53
Derivatives, Average Sold Put Price		44.65
Crude Oil Three-Way Collars For First Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		10,000
Derivative, Average Cap Price		60.00
Derivative, Average Floor Price		55.00
Derivatives, Average Sold Put Price		47.00
Crude Oil Three-Way Collars For Second Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | BBL / Days		10,000
Derivative, Average Cap Price		60.00
Derivative, Average Floor Price		55.00
Derivatives, Average Sold Put Price		47.00
Crude Oil Swaps For the First Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		20,000
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		55.12
Crude Oil Swaps For the Second Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		20,000
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		55.12
Crude Oil Swaps For the Third Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		0
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		0.00
Crude Oil Swaps For the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		0
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		0.00
Crude Oil Swaps For the First Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		0
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		0.00
Crude Oil Swaps For the Second Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		0
Derivative, Average Price Risk Option Strike Price | $ / MMBTU		0.00
Crude Oil Basis Swaps For the First Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		5,000
Weighted Average Differential To WTI Midland and WTI Cushing		(0.60)
Crude Oil Basis Swaps For the Second Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		5,000
Weighted Average Differential To WTI Midland and WTI Cushing		(0.60)
Crude Oil Basis Swaps For the Third Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		10,000
Weighted Average Differential To WTI Midland and WTI Cushing		(0.67)
Crude Oil Basis Swaps For the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		10,000
Weighted Average Differential To WTI Midland and WTI Cushing		(0.67)
Crude Oil Basis Swaps For the First Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		0
Weighted Average Differential To WTI Midland and WTI Cushing		0.00
Crude Oil Basis Swaps For the Second Quarter of Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day		0
Weighted Average Differential To WTI Midland and WTI Cushing		0.00
Natural Gas Three-Way Collars for the First Quarter in Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		200,000
Derivative, Average Cap Price | $ / MMBTU		3.79
Derivative, Average Floor Price | $ / MMBTU		3.08
Derivatives, Average Sold Put Price | $ / MMBTU		2.55
Natural Gas Three-Way Collars For the Second Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU_per_day		160,000
Derivative, Average Cap Price | $ / MMBTU		3.61
Derivative, Average Floor Price | $ / MMBTU		3.00
Derivatives, Average Sold Put Price | $ / MMBTU		2.50
Natural Gas Three-Way Collars For the Third Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		160,000
Derivative, Average Cap Price | $ / MMBTU		3.61
Derivative, Average Floor Price | $ / MMBTU		3.00
Derivatives, Average Sold Put Price | $ / MMBTU		2.50
Natural Gas Three-Way Collars For the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		160,000
Derivative, Average Cap Price | $ / MMBTU		3.61
Derivative, Average Floor Price | $ / MMBTU		3.00
Derivatives, Average Sold Put Price | $ / MMBTU		2.50
Subsequent Event [Member] | Crude Oil Three-Way Collars for July - December 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day	10,000
Derivative, Average Cap Price	63.51
Derivative, Average Floor Price	57.00
Derivatives, Average Sold Put Price	50.00
Subsequent Event [Member] | Crude Oil Three-Way Collars for January - June 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bbls_per_day	20,000
Derivative, Average Cap Price	67.92
Derivative, Average Floor Price	53.50
Derivatives, Average Sold Put Price	46.50

XML

Derivatives (Non Hedges - Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		$ (36)	$ (66)	$ 128
Derivative Net Settlements Received - Commodity		45	$ 44	$ 78
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Cash Proceeds Received from Derivatives	$ 54	54
Interest Rate Swap [Member] | Net Interest and Other [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net		$ 47
Unsecured Debt [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Debt Instrument, Face Amount	$ 1,000

XML

Fair Value Measurements (Details-Recurring) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	$ 0	$ 68
Derivative Liability	(140)	60
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Liability	(140)	60
Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	68
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	(20)	0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Liability	(20)	0
Fair Value, Inputs, Level 1 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	68
Derivative Liability	(120)	60
Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Liability	(120)	60
Fair Value, Inputs, Level 2 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	68
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	$ 0	$ 0

XML

Fair Value Measurements (Details 2-Nonrecurring) - USD ($) $ in Millions	3 Months Ended						12 Months Ended
	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of Oil and Gas Properties							$ 229	$ 67	$ 721
Colorado and Gulf of Mexico [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of Oil and Gas Properties									335
East Texas/North Louisiana and Wilburton Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of Oil and Gas Properties									44
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure			$ 15	$ 15			179	15		$ 56
Impairment of Oil and Gas Properties							229
Assets, Fair Value Adjustment								67	386
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oklahoma Resource Basin [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment Expense - Proved Properties				$ 47
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Colorado and Gulf of Mexico [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure					$ 41
Assets, Fair Value Adjustment					333
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | East Texas/North Louisiana and Wilburton Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Assets, Fair Value Adjustment						$ (44)
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | International Exploration and Production [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 103
Impairment of Oil and Gas Properties	136						136
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Gulf of Mexico Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment Expense - Proved Properties	65						89
Property, Plant, and Equipment, Fair Value Disclosure	$ 66
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | Assets Held and Used Ozona [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Assets, Fair Value Adjustment			$ 17
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member] | EG Equity Method Investment [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure					604
Assets, Fair Value Adjustment					$ 12
Oil Sands Mining Segment [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of Oil and Gas Properties		$ 6,600					$ 6,636	$ 0	$ 31

XML

Fair Value Measurements (Details 3-Reported)		12 Months Ended
	May 31, 2017 USD ($)	Dec. 31, 2017 USD ($) notes_receivable	Dec. 31, 2016 USD ($)
Estimate of Fair Value Measurement [Member]
Financial assets
Other current assets		$ 762,000,000	$ 7,000,000
Other noncurrent assets		159,000,000	105,000,000
Total financial assets		921,000,000	112,000,000
Financial liabilities
Other current liabilities		32,000,000	68,000,000
Long-term debt, including current portion(a)		5,976,000,000	7,449,000,000
Deferred credits and other liabilities		110,000,000	114,000,000
Total financial liabilities		6,118,000,000	7,631,000,000
Reported Value Measurement [Member]
Financial assets
Other current assets		761,000,000	7,000,000
Other noncurrent assets		161,000,000	108,000,000
Total financial assets		922,000,000	115,000,000
Financial liabilities
Other current liabilities		43,000,000	75,000,000
Long-term debt, including current portion(a)		5,526,000,000	7,292,000,000
Deferred credits and other liabilities		103,000,000	107,000,000
Total financial liabilities		$ 5,672,000,000	$ 7,474,000,000
Oil Sands Mining Segment [Member] | Discontinued Operations, Disposed of by Sale [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Number of notes receivable	2	2

XML

Debt Revolver (Details)	1 Months Ended	12 Months Ended
	Jul. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) extension	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 30, 2017 USD ($)	May 31, 2015
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent		$ 5,536,000,000	$ 7,301,000,000
Line of Credit Facility, Expiration Date		May 31, 2020
Ratio of Indebtedness to Net Capital		0.32
Derivative, Gain (Loss) on Derivative, Net		$ (36,000,000)	$ (66,000,000)	$ 128,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 3,400,000,000	3,400,000,000			$ 3,300,000,000
Line of Credit Facility, Increase (Decrease), Net	$ 93,000,000
Line of Credit Facility, Maximum Borrowing Capacity		$ 0
Line of Credit Facility, Number of One Year Extensions | extension		2
Line of Credit, Period of Extension Options		1 year
Line of Credit Facility, Remaining Borrowing Capacity		$ 107,000,000
Bridge Loan [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		100,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 500,000,000
Maximum [Member]
Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital						0.65

XML

Debt (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 24, 2017
Debt Instrument [Line Items]
Gain (Loss) on Extinguishment of Debt			$ (51,000,000)	$ 0	$ 0
Other Long-term Debt, Noncurrent	$ 5,536,000,000		5,536,000,000	7,301,000,000
Unamortized Discount	(10,000,000)		(10,000,000)	(9,000,000)
Fair value adjustments	0		0	7,000,000
Unamortized Debt Issuance Expense	(32,000,000)		(32,000,000)	(35,000,000)
Amounts due within one year	0		0	(683,000,000)
Total long-term debt due after one year	5,494,000,000		5,494,000,000	6,581,000,000
Debt Immediately Due If Change In Control	236,000,000		236,000,000
Proceeds from Issuance of Debt		$ 990,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
2015	0		0
2016	0		0
2017	600,000,000		600,000,000
2018	0		0
2019	1,035,000,000		1,035,000,000
Thereafter	3,901,000,000		3,901,000,000
Other Long-term Debt, Noncurrent	$ 5,536,000,000		$ 5,536,000,000	7,301,000,000
Senior Unsecured Notes Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						4.40%
Other Long-term Debt, Noncurrent						$ 1,000,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent						$ 1,000,000,000
Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%		6.00%
Other Long-term Debt, Noncurrent	$ 0		$ 0	682,000,000
Unsecured Debt, Current	682,000,000		682,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 0		$ 0	682,000,000
Senior Unsecured Notes Due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.90%		5.90%
Other Long-term Debt, Noncurrent	$ 0		$ 0	854,000,000
Unsecured Debt, Current	854,000,000		854,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 0		$ 0	854,000,000
Senior Unsecured Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%		7.50%
Other Long-term Debt, Noncurrent	$ 0		$ 0	228,000,000
Unsecured Debt, Current	228,000,000		228,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 0		$ 0	228,000,000
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.70%		2.70%
Other Long-term Debt, Noncurrent	$ 600,000,000		$ 600,000,000	600,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 600,000,000		$ 600,000,000	600,000,000
Senior Unsecured Notes Due 2022 [A] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.80%		2.80%
Other Long-term Debt, Noncurrent	$ 1,000,000,000		$ 1,000,000,000	1,000,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 1,000,000,000		$ 1,000,000,000	1,000,000,000
Senior Unsecured Notes Due 2022 [B] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.375%		9.375%
Other Long-term Debt, Noncurrent	$ 32,000,000		$ 32,000,000	32,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	32,000,000		32,000,000	32,000,000
Series Medium Term Notes Due 2022 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	3,000,000		3,000,000	3,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 3,000,000		$ 3,000,000	3,000,000
Senior Unsecured Notes Due 2023 [A] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.50%		8.50%
Other Long-term Debt, Noncurrent	$ 70,000,000		$ 70,000,000	70,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 70,000,000		$ 70,000,000	70,000,000
Senior Unsecured Notes Due 2023 [B] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.125%		8.125%
Other Long-term Debt, Noncurrent	$ 131,000,000		$ 131,000,000	131,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 131,000,000		$ 131,000,000	131,000,000
Senior Unsecured Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.85%		3.85%
Other Long-term Debt, Noncurrent	$ 900,000,000		$ 900,000,000	900,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 900,000,000		$ 900,000,000	900,000,000
Senior Unsecured Notes Due 2032 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.80%		6.80%
Other Long-term Debt, Noncurrent	$ 550,000,000		$ 550,000,000	550,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 550,000,000		$ 550,000,000	550,000,000
Notes Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.40%		4.40%
Other Long-term Debt, Noncurrent	$ 1,000,000,000		$ 1,000,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 1,000,000,000		$ 1,000,000,000
Senior Unsecured Notes Due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.60%		6.60%
Other Long-term Debt, Noncurrent	$ 750,000,000		$ 750,000,000	750,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 750,000,000		$ 750,000,000	750,000,000
Senior Unsecured Notes Due 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.20%		5.20%
Other Long-term Debt, Noncurrent	$ 500,000,000		$ 500,000,000	500,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	500,000,000		500,000,000	500,000,000
Capital Lease Obligation of Consolidated Subsidiary due 2016 - 2049 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	0		0	1,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	$ 0		$ 0	1,000,000
Obligation Relating To Revenue Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.125%		5.125%
Extinguishment of Debt, Amount	$ 1,000,000,000
Other Long-term Debt, Noncurrent	0		$ 0	1,000,000,000
Long-term Debt, Fiscal Year Maturity [Abstract]
Other Long-term Debt, Noncurrent	0		0	$ 1,000,000,000
Unsecured Debt [Member]
Debt Instrument [Line Items]
Gain (Loss) on Extinguishment of Debt			(46,000,000)
Extinguishment of Debt, Amount			1,760,000,000
Municipal Revenue Bonds Due 2037 [Member] | The Parish [Member]
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 1,000,000,000		$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.75%		3.75%

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Incentive Based Compensation Plans (Details-All) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized	55,000,000
Maximum award for options or stock appreciation rights	2.41
Granted, stock option awards (in shares)	799,591
Allocated stock-based compensation expense	$ 50,000,000	$ 51,000,000	$ 57,000,000
Tax benefit from compensation expense		19,000,000	20,000,000
Proceeds from stock options exercised		1,000,000	9,000,000
Tax benefit realized from exercise of stock options	$ 0	$ 0	$ 0
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Stock Option [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award contractual period	10 years
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, stock option awards (in shares)	0
Restricted Stock [Member] | Granted Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Restricted Stock [Member] | Non Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Stock Compensation Plan [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights, percentage	0.00%
Stock Compensation Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights, percentage	200.00%
Restricted Stock Units (RSUs) [Member] | Non Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Share-based Compensation Plans Prior to the 2016 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, stock option awards (in shares)	0

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Incentive Based Compensation Plans - Stock Option Award Assumptions (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Incentive Based Compensation Plans [Abstract]
Employee Service Share-based Compensation, Tax Benefit from Exercise of Stock Options	$ 0	$ 0	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Exercise price per share (in dollars per share)	$ 15.80	$ 7.22	$ 29.06
Expected annual dividend yield	1.30%	2.80%	2.90%
Expected life in years	6 years 4 months 24 days	6 years 3 months 26 days	6 years 2 months 12 days
Expected volatility	42.00%	36.00%	32.00%
Risk-free interest rate	2.10%	1.40%	1.70%
Weighted average grant date fair value of stock option awards granted (in dollars per share)	$ 6.07	$ 1.97	$ 6.84

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Incentive Based Compensation Plans - Stock Option Award Activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Shares
Beginning of year, stock option awards (in shares)	11,915,533
Granted, stock option awards (in shares)	799,591
Exercised, stock option awards (in shares)	(8,666)
Canceled, stock option awards (in shares)	(2,375,682)
End of year, stock option awards (in shares)	10,330,776	11,915,533
Exercisable at end of year, stock option awards (in shares)	8,661,893
Expected to vest, stock option awards (in shares)	1,650,737
Weighted Average Exercise Price
Beginning of year, weighted average exercise price (in dollars per share)	$ 27.71
Granted, weighted average exercise price (in dollars per share)	15.80	$ 7.22	$ 29.06
Exercises, weighted average exercise price (in dollars per share)	7.22
Canceled, weighted average exercise price (in dollars per share)	33.31
End of year, weighted average exercise price (in dollars per share)	25.52	$ 27.71
Exercisable at end of year, weighted average exercise price (in dollars per share)	27.91
Expected to vest, weighted average exercise price (in dollars per share)	$ 13.08
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Outstanding at end of year, Weighted Average Remaining Contractual Term	4 years
Exercisable at end of year, Weighted Average Remaining Contractual Term	3 years
Expected to vest, Weighted Average Remaining Contractual Term	9 years
Outstanding at end of year, Average Intrinsic Value	$ 13
Exercisable at end of year, Average Intrinsic Value	5
Expected to vest, Average Intrinsic Value	8
Stock option awards, intrinsic value			$ 6
Unrecognized compensation costs	$ 4
Unrecognized compensation costs, period for recognition	1 year

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Incentive Based Compensation Plans - Restricted Stock Awards and RSUs (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted Average Grant Date Fair Value
Unrecognized compensation costs	$ 4
Unrecognized compensation costs, period for recognition	1 year
Restricted Stock [Member]
Awards
Unvested at beginning of year (in shares)	6,933,533
Granted (in shares)	4,198,624
Vested & Exercised (in shares)	(2,472,367)
Canceled (in shares)	(1,086,945)
Unvested at end of year (in shares)	7,572,845	6,933,533
Weighted Average Grant Date Fair Value
Unvested at beginning of year (in dollars per share)	$ 14.44	$ 30.76
Granted (in dollars per share)	16.13
Vested & Exercised (in dollars per share)	17.67
Canceled (in dollars per share)	15.03
Unvested at end of year (in dollars per share)	$ 14.24	$ 14.44	$ 30.76
Vested in period, total fair value	$ 30	$ 16	$ 26
Unrecognized compensation costs	$ 67
Unrecognized compensation costs, period for recognition	1 year

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Incentive Based Compensation Plans - Performance Unit Awards (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Tax Benefit from Exercise of Stock Options	$ 0	$ 0	$ 0
Allocated stock-based compensation expense	$ 50,000,000	$ 51,000,000	$ 57,000,000
Expected annual dividend yield	1.30%	2.80%	2.90%
Expected volatility	42.00%	36.00%	32.00%
Risk-free interest rate	2.10%	1.40%	1.70%
Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units (in shares)	1,510,823
Allocated stock-based compensation expense	$ 8,000,000	$ 6,000,000	$ 0
Valuation date stock price (in dollars per share)	$ 16.93	$ 16.93	$ 16.93
Expected annual dividend yield	1.20%	1.20%	1.20%
Expected volatility	54.00%	34.00%	33.00%
Risk-free interest rate	1.90%	1.70%	1.40%
Fair value of stock-based performance units outstanding	$ 21.63	$ 19.86	$ 0.00
Granted Officer [Member] | Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants in period (in shares)	563,631	1,205,517	382,335
2015 [Member] | Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested units (in shares)	0

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Obligations and Funded Status)(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
UNITED STATES
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Accumulated benefit obligation	$ 378	$ 386
Change in benefit obligations:
Benefit obligations at January 1	397	525
Service cost	22	25
Interest cost	13	16
Plan amendment	0	0
Actuarial loss	42	78
Foreign currency exchange rate changes	0	0
Divestiture	0	0
Settlements paid	(84)	(240)
Benefits paid	(6)	(7)
Benefit obligations at December 31	384	397
Change in fair value of plan assets:
Fair value of plan assets at January 1	227	354
Actual return on plan assets	27	25
Employer contributions	52	95
Foreign currency exchange rate changes	0	0
Divestiture	0	0
Settlements paid	(84)	(240)
Benefits paid	(6)	(7)
Fair value of plan assets at December 31	216	227
Funded status of plans at December 31
Funded status of plans at December 31	(168)	(170)
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	0	0
Current liabilities	(6)	(4)
Noncurrent liabilities	(162)	(166)
Accrued benefit cost	(168)	(170)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	122	130
Prior service cost (credit)	(45)	(55)
Foreign Plan [Member]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Accumulated benefit obligation	599	583
Change in benefit obligations:
Benefit obligations at January 1	583	579
Service cost	0	0
Interest cost	17	23
Plan amendment	0	1
Actuarial loss	(7)	139
Foreign currency exchange rate changes	52	(108)
Divestiture	0	0
Settlements paid	(31)	(36)
Benefits paid	(15)	(15)
Benefit obligations at December 31	599	583
Change in fair value of plan assets:
Fair value of plan assets at January 1	595	608
Actual return on plan assets	47	129
Employer contributions	17	18
Foreign currency exchange rate changes	57	(109)
Divestiture	0	0
Settlements paid	(31)	(36)
Benefits paid	(15)	(15)
Fair value of plan assets at December 31	670	595
Funded status of plans at December 31
Funded status of plans at December 31	71	12
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	71	12
Current liabilities	0	0
Noncurrent liabilities	0	0
Accrued benefit cost	71	12
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	58	81
Prior service cost (credit)	3	4
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Accumulated benefit obligation	221	227
Change in benefit obligations:
Benefit obligations at January 1	227	260
Service cost	2	2
Interest cost	8	11
Plan amendment	0	(38)
Actuarial loss	5	11
Foreign currency exchange rate changes	0	0
Divestiture	0	0
Settlements paid	0	0
Benefits paid	(21)	(19)
Benefit obligations at December 31	221	227
Change in fair value of plan assets:
Fair value of plan assets at January 1	0	0
Actual return on plan assets	0	0
Employer contributions	21	20
Foreign currency exchange rate changes	0	0
Divestiture	0	0
Settlements paid	0	0
Benefits paid	(21)	(20)
Fair value of plan assets at December 31	0	0
Funded status of plans at December 31
Funded status of plans at December 31	(221)	(227)
Amounts recognized in the consolidated balance sheets:
Noncurrent assets	0	0
Current liabilities	(21)	(21)
Noncurrent liabilities	(200)	(206)
Accrued benefit cost	(221)	(227)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	30	25
Prior service cost (credit)	$ (56)	$ (63)

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Schedule of Net Periodic Benefit Cost and OCI)(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Foreign Plan [Member]
Components of net periodic benefit cost:
Service cost	$ 0	$ 0	$ 14
Interest cost	17	23	25
Expected return on plan assets	(30)	(35)	(37)
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	0	1	1
- actuarial loss	1	0	2
Net curtailment loss (gain)	0	0	4
Net settlement loss	4	6	0
Net periodic benefit cost	(8)	(5)	9
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	(26)	41	(25)
Amortization of actuarial (loss) gain	(4)	(6)	(2)
Prior service cost	0	1	1
Amortization of prior service credit (cost)	0	(1)	(5)
Total recognized in other comprehensive (income) loss	(30)	35	(31)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	(38)	30	(22)
UNITED STATES
Components of net periodic benefit cost:
Service cost	22	25	29
Interest cost	13	16	25
Expected return on plan assets	(13)	(18)	(30)
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	(10)	(10)	(7)
- actuarial loss	8	14	22
Net curtailment loss (gain)	0	0	(5)
Net settlement loss	28	97	119
Net periodic benefit cost	48	124	153
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	28	70	30
Amortization of actuarial (loss) gain	(36)	(111)	(134)
Prior service cost	0	0	(89)
Amortization of prior service credit (cost)	10	10	7
Total recognized in other comprehensive (income) loss	2	(31)	(186)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	50	93	(33)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost:
Service cost	2	2	3
Interest cost	8	11	11
Expected return on plan assets	0	0	0
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	(7)	(3)	(4)
- actuarial loss	0	0	1
Net curtailment loss (gain)	0	0	(7)
Net settlement loss	0	0	0
Net periodic benefit cost	3	10	4
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	5	11	(21)
Amortization of actuarial (loss) gain	0	0	(1)
Prior service cost	0	(38)	0
Amortization of prior service credit (cost)	7	3	13
Total recognized in other comprehensive (income) loss	12	(24)	(9)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$ 15	$ (14)	$ (5)
Scenario, Forecast [Member]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Gains (Losses)				$ 13
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)				10
Scenario, Forecast [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Gains (Losses)				1
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)				$ 7

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Plan Assumptions)(Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
UNITED STATES
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.55%	4.02%	4.04%
Rate of compensation increase	4.00%	4.00%	4.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.86%	3.66%	3.79%
Expected long-term return on plan assets	6.50%	6.75%	6.75%
Rate of compensation increase	4.00%	4.00%	4.00%
Foreign Plan [Member]
Weighted average assumptions used to determine benefit obligation:
Discount rate	2.50%	2.70%	3.90%
Rate of compensation increase	0.00%	0.00%	0.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	2.70%	3.90%	3.70%
Expected long-term return on plan assets	4.50%	5.50%	5.70%
Rate of compensation increase	0.00%	0.00%	3.60%
Other Postretirement Benefit Plans, Defined Benefit [Member]
Weighted average assumptions used to determine benefit obligation:
Discount rate	3.54%	3.98%	4.36%
Rate of compensation increase	4.00%	4.00%	4.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.98%	4.36%	3.93%
Expected long-term return on plan assets	0.00%	0.00%	0.00%
Rate of compensation increase	4.00%	4.00%	4.00%

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Health Care Cost Trends Table and Narrative)(Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Initial health care trend rate	8.00%	8.25%	8.00%
Ultimate trend rate	4.70%	4.50%	4.50%
Year ultimate trend rate is reached	2025	2025	2024
Foreign Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Target allocation percentage	55.00%
Foreign Plan [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Target allocation percentage	45.00%
UNITED STATES | Equity Securities [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Target allocation percentage	55.00%
UNITED STATES | Fixed Income Securities [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Target allocation percentage	45.00%

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Fair Value of Defined Benefit Pension Plan Assets)(Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
UNITED STATES
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 216	$ 227	$ 354
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	157	213
UNITED STATES | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	8
UNITED STATES | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	81	82
UNITED STATES | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16	20
UNITED STATES | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
UNITED STATES | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	52
UNITED STATES | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5	5
UNITED STATES | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	24	25
UNITED STATES | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
UNITED STATES | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	19	21
UNITED STATES | Commingled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	59	14
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0
Foreign Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	670	595	$ 608
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	670	595
Foreign Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	5
Foreign Plan [Member] | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Foreign Plan [Member] | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Foreign Plan [Member] | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	266	360
Foreign Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Foreign Plan [Member] | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Foreign Plan [Member] | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Foreign Plan [Member] | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	403	230
Foreign Plan [Member] | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | UNITED STATES
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	111	101
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	111	101
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	8
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	81	82
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5	5
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	19	6
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | UNITED STATES | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	152	206
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	152	206
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	5
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	151	201
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Plan [Member] | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	8	71
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	8	71
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6	52
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2	19
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | UNITED STATES | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	518	389
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	518	389
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	115	159
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	403	230
Fair Value, Inputs, Level 2 [Member] | Foreign Plan [Member] | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	38	41
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	38	41
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16	20
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | UNITED STATES | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	19	21
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Defined Benefit Plan, Fair Value of Plan Assets, Before Commingled Funds	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Common And Preferred Stock [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Private Equity And Reit [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Mutual And Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Exchange Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | US Treasury and Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Plan [Member] | MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Cash Flows)(Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Employer discretionary contribution amount	$ 20	$ 20	$ 20
Scenario, Forecast [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Estimated future employer contributions in 2018				$ 65
UNITED STATES
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
2018	43
2019	40
2020	37
2021	33
2022	30
2023 through 2027	123
Foreign Plan [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
2018	17
2019	18
2020	17
2021	19
2022	21
2023 through 2027	118
Unfunded Plans [Member] | Scenario, Forecast [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Estimated future employer contributions in 2018				6
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
2018	21
2019	20
2020	20
2021	19
2022	18
2023 through 2027	$ 74
Other Postretirement Benefit Plans, Defined Benefit [Member] | Scenario, Forecast [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
Estimated future employer contributions in 2018				$ 21

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Reclassifications Out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Provision for income taxes	$ (376)	$ (923)	$ 738
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Amortization of actuarial loss	(9)	(14)
Net settlement loss	(32)	(103)
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	46	0
Derivative Instruments, Income Statement Location of Gain (Loss) Reclassified from Accumulated OCI	1	4
Income from operations before income taxes	6	(113)
Provision for income taxes	(40)	41
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	(34)	(72)
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Reclassification Adjustment from AOCI, Realized upon Sale or Liquidation, Net of Tax	(30)	0
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent	$ (64)	$ (72)

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Interest paid (net of amounts capitalized)	$ (379)	$ (375)	$ (325)
Income taxes paid to taxing authorities	(391)	(84)	(171)
Commercial paper:
Asset Retirement Obligation, Period Increase (Decrease)	(202)	110	(95)
Noncash investing and financing activities:
Increase in capital expenditure accrual	176	0	0
Asset Retirement Obligation, Liabilities Transferred	14	40	251
Notes, Loans and Financing Receivable, Net, Current	748	0
Receivable Related To Disposal Of Assets		$ 0	$ 0
Foreign Tax Authority [Member] | UK Government [Member]
Income Tax Examination [Line Items]
Income Tax Examination, Penalties and Interest Expense	$ 108

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Other Items (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Interest and Other Financing [Abstract]
Interest income	$ 34	$ 14	$ 9
Interest expense(a)	(380)	(398)	(350)
Income on interest rate swaps	53	13	11
Interest capitalized	3	18	19
Total interest	(290)	(353)	(311)
Net foreign currency gains (losses)	8	6	4
Other	12	15	21
Total other	20	21	25
Net interest and other	(270)	(332)	(286)
Aggregate foreign currency gains losses [Abstract]
Net interest and other	8	6	4
Provision for income taxes	57	(32)	(11)
Aggregate foreign currency gains (losses)	$ 65	$ (26)	$ (7)

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Equity Method Investments and Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Method Investments Disclosure [Abstract]
Proceeds from Equity Method Investment, Distribution	$ 276	$ 192	$ 178
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	847	931
Equity Method Investment, Summarized Financial Information [Abstract]
Revenues and other income	1,294	770	769
Income from operations	631	346	313
Net income	508	313	280
Current assets	586	525
Noncurrent assets	1,044	1,173
Current liabilities	221	218
Noncurrent liabilities	94	47
Related Party Transactions [Abstract]
Revenue from Related Parties	60	54	51
Related Party Transaction, Purchases from Related Party	132	103	$ 207
Accounts Receivable, Related Parties, Current	24	23
Accounts Payable, Related Parties, Current	$ 14	11
EG Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	60.00%
Equity Method Investments	$ 456	550
Alba Plant LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	52.00%
Equity Method Investments	$ 214	215
AMPCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	45.00%
Equity Method Investments	$ 177	165
Other Equity Method Investees [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 0	$ 1

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Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity, Class of Treasury Stock [Line Items]
Stock Issued During Period, Shares, New Issues	166,750,000
Treasury Stock, Value, Acquired, Cost Method		$ 11	$ 5	$ 8
Common stock, par value per share	$ 1	$ 1	$ 1
Shares Issued, Price Per Share	$ 7.65
Stock Issued	$ 1,236
Share Repurchase Program [Member]
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Remaining Authorized Repurchase Amount		$ 1,500

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Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Year 1 Operating	$ 29
Year 2 Operating	28
Year 3 Operating	27
Year 4 Operating	26
Year 5 Operating	5
Later years, Operating Leases	4
Sublease rentals	0
Operating Leases, Future Minimum Payments Due	119
Operating Leases, Rent Expense, Net [Abstract]
Operating Leases, Rent Expense	$ 87	$ 87	$ 99

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Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Guarantor Obligations [Line Items]
Override Royalty - GOM Future Abandonment	$ 70
Payments to Acquire Property, Plant, and Equipment [Abstract]
Commitments to acquire property, plant and equipment	102	$ 144
Other Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	35
UK Government [Member] | Foreign Tax Authority [Member]
Guarantor Obligations [Line Items]
Income Tax Examination, Penalties and Interest Expense	$ 108