10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, 2015

OR

[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _____ to _____

Commission file number 1-5153

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)

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes R No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         

Yes o No þ

There were 677,260,116 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2015.

MARATHON OIL CORPORATION

Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q 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).

For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2014 Annual Report on Form 10-K.

	Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 5.	Other Information	41
Item 6.	Exhibits	41
	Signatures	42

1

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except per share data)	2015			2014			2015			2014
Revenues and other income:
Sales and other operating revenues, including related party	$	1,300		$	2,316		$	3,887		$	6,735
Marketing revenues	84			554			471			1,713
Income from equity method investments	36			89			98			346
Net loss on disposal of assets	(109		)	(3		)	(108		)	(88		)
Other income	12			15			38			55
Total revenues and other income	1,323			2,971			4,386			8,761
Costs and expenses:
Production	406			593			1,300			1,697
Marketing, including purchases from related parties	84			554			471			1,710
Other operating	93			99			281			303
Exploration	585			96			786			314
Depreciation, depletion and amortization	717			737			2,289			2,060
Impairments	337			109			381			130
Taxes other than income	46			115			191			319
General and administrative	125			160			464			486
Total costs and expenses	2,393			2,463			6,163			7,019
Income (loss) from operations	(1,070		)	508			(1,777		)	1,742
Net interest and other	(75		)	(55		)	(180		)	(180		)
Income (loss) from continuing operations before income taxes	(1,145		)	453			(1,957		)	1,562
Provision (benefit) for income taxes	(396		)	149			(546		)	500
Income (loss) from continuing operations	(749		)	304			(1,411		)	1,062
Discontinued operations	—			127			—			1,058
Net income (loss)	$	(749	)	$	431		$	(1,411	)	$	2,120
Per basic share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45		$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64		$	(2.09	)	$	3.11
Per diluted share:
Income (loss)from continuing operations	$	(1.11	)	$	0.45		$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64		$	(2.09	)	$	3.10
Dividends per share	$	0.21		$	0.21		$	0.63		$	0.59
Weighted average common shares outstanding:
Basic	677			675			677			681
Diluted	677			678			677			684

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

2

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015			2014			2015			2014
Net income (loss)	$	(749	)	$	431		$	(1,411	)	$	2,120
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(2		)	3			160			(40		)
Income tax benefit (provision)	(1		)	(2		)	(58		)	13
Postretirement and postemployment plans, net of tax	(3		)	1			102			(27		)
Comprehensive income (loss)	$	(752	)	$	432		$	(1,309	)	$	2,093

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

3

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
(In millions, except per share data)	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	1,680		$	2,398
Short-term investments	700			—
Receivables, less reserve of $4 and $3	991			1,729
Inventories	324			357
Other current assets	163			109
Total current assets	3,858			4,593
Equity method investments	1,012			1,113
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,713 and $21,884	27,920			29,040
Goodwill	457			459
Other noncurrent assets	1,427			806
Total assets	$	34,674		$	36,011
Liabilities
Current liabilities:
Accounts payable	$	1,246		$	2,545
Payroll and benefits payable	138			191
Accrued taxes	143			285
Other current liabilities	286			290
Long-term debt due within one year	1,035			1,068
Total current liabilities	2,848			4,379
Long-term debt	7,323			5,323
Deferred tax liabilities	2,542			2,486
Defined benefit postretirement plan obligations	436			598
Asset retirement obligations	1,965			1,917
Deferred credits and other liabilities	225			288
Total liabilities	15,339			14,991
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 93 million and 95 million shares	(3,553		)	(3,642		)
Additional paid-in capital	6,493			6,531
Retained earnings	15,800			17,638
Accumulated other comprehensive loss	(175		)	(277		)
Total stockholders' equity	19,335			21,020
Total liabilities and stockholders' equity	$	34,674		$	36,011

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

4

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
(In millions)	2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(1,411	)	$	2,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(1,058		)
Deferred income taxes	(590		)	337
Depreciation, depletion and amortization	2,289			2,060
Impairments	381			130
Pension and other postretirement benefits, net	9			(27		)
Exploratory dry well costs and unproved property impairments	708			220
Net loss on disposal of assets	108			88
Equity method investments, net	41			51
Changes in:
Current receivables	738			(270		)
Inventories	30			(32		)
Current accounts payable and accrued liabilities	(954		)	(115		)
All other operating, net	(136		)	(28		)
Net cash provided by continuing operations	1,213			3,476
Net cash provided by discontinued operations	—			856
Net cash provided by operating activities	1,213			4,332
Investing activities:
Acquisitions, net of cash acquired	—			(12		)
Additions to property, plant and equipment	(2,948		)	(3,639		)
Disposal of assets	105			2,237
Investments - return of capital	61			46
Purchases of short-term investments	(925		)	—
Maturities of short-term investments	225			—
Investing activities of discontinued operations	—			(356		)
All other investing, net	22			(24		)
Net cash used in investing activities	(3,460		)	(1,748		)
Financing activities:
Commercial paper, net	—			(135		)
Borrowings	1,996			—
Debt issuance costs	(19		)	—
Debt repayments	(34		)	(34		)
Purchases of common stock	—			(1,000		)
Dividends paid	(427		)	(401		)
All other financing, net	14			150
Net cash provided by (used in) financing activities	1,530			(1,420		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	(1		)	(1		)
Discontinued operations	—			(11		)
Cash held for sale	—			(655		)
Net increase (decrease) in cash and cash equivalents	(718		)	497
Cash and cash equivalents at beginning of period	2,398			264
Cash and cash equivalents at end of period	$	1,680		$	761

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

5

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1.    Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.

As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2014 Annual Report on Form 10-K.  The results of operations for the third quarter and first nine months of2015 are not necessarily indicative of the results to be expected for the full year.

2.   Accounting Standards

Not Yet Adopted

In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner by which a reporting entity assesses whether the equity holders at risk lack decision making rights if the decision-making over the subject entity’s most significant activities was outsourced. This standard is effective for us in the first quarter of 2016 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards.  This standard is effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2014, 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 also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter of 2017. 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.

6

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Recently Adopted

In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required.  In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations.  The amendments were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact our consolidated results of operations, financial position or cash flows.

3.   Variable Interest Entity

The owners of the Athabasca Oil Sands Project, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at September 30, 2015 and $3 million at December 31, 2014.  This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE.  We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $471 million as of September 30, 2015.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.

4. 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, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 2 million stock options for the third quarters of 2015 and 2014 and 13 million and 4 million stock options for the first nine months of 2015 and 2014 that were antidilutive.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2015			2014		2015			2014
Income (loss) from continuing operations	$	(749	)	$	304	$	(1,411	)	$	1,062
Discontinued operations	—			127		—			1,058
Net income (loss)	$	(749	)	$	431	$	(1,411	)	$	2,120
Weighted average common shares outstanding	677			675		677			681
Effect of dilutive securities	—			3		—			3
Weighted average common shares, diluted	677			678		677			684
Per basic share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.10

7

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

5. Acquisitions

2014 - North America E&P Segment

In the third quarter of 2014, we acquired acreage in the Oklahoma Resource Basins at a cost of $68 million after final settlement adjustments.

6. Dispositions

2015 - North America E&P Segment

In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (See Note 15).

2015 - International E&P Segment

In September 2015, we entered into an agreement 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 is expected to close during the fourth quarter of 2015.

2014 - North America E&P Segment

In the second quarter of 2014, we closed the sale of non-core acreage located in the far northwest portion of Williston Basin for proceeds of $90 million and recorded a pretax loss of $91 million.

2014 - International E&P Segment

In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea.  The transaction closed during the fourth quarter of 2014.

Our Norway business was reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2014. Select amounts reported in discontinued operations were as follows:

	Three Months Ended September 30,			Nine Months Ended September 30,
(In millions)		2014			2014
Revenues applicable to discontinued operations		$	528		$	1,901
Pretax income from discontinued operations		$	487		$	1,617
After-tax income from discontinued operations		$	127		$	449	(a)

^(a)Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.

In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.

Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the prior period. Select amounts reported in discontinued operations were as follows:

	Nine Months Ended September 30,
(In millions)	2014
Revenues applicable to discontinued operations	$	58
Pretax income from discontinued operations, before gain	$	51
Pretax gain on disposition of discontinued operations	$	470
After-tax income from discontinued operations	$	609

8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.    Segment Information

  We are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;

• Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

• Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

As discussed in Note 6, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the Int'l E&P segment for 2014.

	Three Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	796		$	182	$	242		$	80		(c)	$	1,300
Marketing revenues	57			25		2			—				84
Total revenues	853			207		244			80				1,384
Income (loss) from equity method investments	—			48		—			(12		)	(d)	36
Net gain (loss) on disposal of assets and other income	6			6		—			(109		)	(e)	(97		)
Less:
Production expenses	179			61		166			—				406
Marketing costs	56			25		3			—				84
Exploration expenses	22			10		—			553			(f)	585
Depreciation, depletion and amortization	549			79		76			13				717
Impairments	—			—		4			333			(g)	337
Other expenses (a)	106			25		8			79			(h)	218
Taxes other than income	42			—		5			(1		)		46
Net interest and other	—			—		—			75				75
Income tax provision (benefit)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Capital expenditures (b)	$	564		$	30	$	(11	)	$	12			$	595

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).

9

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended September 30, 2014
								Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,586		$	273	$	457	$	—			$	2,316
Marketing revenues	506			46		2		—				554
Total revenues	2,092			319		459		—				2,870
Income from equity method investments	—			89		—		—				89
Net gain (loss) on disposal of assets and other income	(1		)	12		—		1				12
Less:
Production expenses	233			108		252		—				593
Marketing costs	507			45		2		—				554
Exploration expenses	55			41		—		—				96
Depreciation, depletion and amortization	609			55		62		11				737
Impairments	—			—		—		109			(c)	109
Other expenses (a)	118			26		14		101			(d)	259
Taxes other than income	109			—		5		1				115
Net interest and other	—			—		—		55				55
Income tax provision (benefit)	168			39		31		(89		)		149
Segment income/Income from continuing operations	$	292		$	106	$	93	$	(187	)		$	304
Capital expenditures (b)	$	1,277		$	166	$	49	$	16			$	1,508

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Proved property impairment (See Note 14).

^(d)  Includes pension settlement loss of $22 million (See Note 8).

	Nine Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	2,639		$	575	$	614		$	59		(c)	$	3,887
Marketing revenues	345			81		45			—				471
Total revenues	2,984			656		659			59				4,358
Income (loss) from equity method investments	—			110		—			(12		)	(d)	98
Net gain (loss) on disposal of assets and other income	17			20		1			(108		)	(e)	(70		)
Less:
Production expenses	560			192		548			—				1,300
Marketing costs	348			79		44			—				471
Exploration expenses	148			85		—			553			(f)	786
Depreciation, depletion and amortization	1,866			214		173			36				2,289
Impairments	—			—		4			377			(g)	381
Other expenses (a)	322			67		26			330			(h)	745
Taxes other than income	170			—		15			6				191
Net interest and other	—			—		—			180				180
Income tax provision (benefit)	(146		)	56		(43		)	(413		)	(i)	(546		)
Segment income (loss) /Loss from continuing operations	$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Capital expenditures (b)	$	2,048		$	275	$	26		$	26			$	2,375

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity-method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).

⁽ⁱ⁾  Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (See Note 9).

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Nine Months Ended September 30, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	4,518	$	1,000	$	1,217	$	—			$	6,735
Marketing revenues	1,486		177		50		—				1,713
Total revenues	6,004		1,177		1,267		—				8,448
Income from equity method investments	—		346		—		—				346
Net gain (loss) on disposal of assets and other income	17		44		3		(97		)	(c)	(33		)
Less:
Production expenses	661		307		729		—				1,697
Marketing costs	1,484		176		50		—				1,710
Exploration expenses	194		120		—		—				314
Depreciation, depletion and amortization	1,674		201		152		33				2,060
Impairments	21		—		—		109			(d)	130
Other expenses (a)	354		98		40		297			(e)	789
Taxes other than income	301		—		16		2				319
Net interest and other	—		—		—		180				180
Income tax provision (benefit)	496		178		71		(245		)		500
Segment income /Income from continuing operations	$	836	$	487	$	212	$	(473	)		$	1,062
Capital expenditures (b)	$	3,246	$	386	$	172	$	29			$	3,833

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Primarily related to the sale of non-core acreage (See Note 6).

^(d)  Proved property impairments (See Note 14).

^(e)  Includes pension settlement loss of $93 million (See Note 8).

8.    Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	11		$	12		$	—		$	—
Interest cost	12			15			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	(3		)	1			(1		)	(1		)
– actuarial loss	5			7			1			—
Net settlement loss (a)	18			22			—			—
Net curtailment loss (b)	4			—			—			—
Net periodic benefit cost	$	30		$	41		$	3		$	3

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	35		$	35		$	2		$	2
Interest cost	39			46			8			10
Expected return on plan assets	(53		)	(48		)	—			—
Amortization:
– prior service cost (credit)	(4		)	4			(3		)	(3		)
– actuarial loss	19			23			1			—
Net settlement loss(a)	99			93			—			—
Net curtailment loss (gain) (b)	5			—			(4		)	—
Net periodic benefit cost	$	140		$	153		$	4		$	9

^(a)  Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.

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

During the first nine months of 2015, we recorded the effects of a workforce reduction, a U.S. pension plan amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula and was effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first nine months of 2015 and 2014, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.

During the first nine months of 2015, we made contributions of $65 million to our funded pension plans.  We expect to make additional contributions up to an estimated $18 million to our funded pension plans over the remainder of 2015.  During the first nine months of 2015, we made payments of $57 million and $13 million related to unfunded pension plans and other postretirement benefit plans, respectively.

9.    Income Taxes

Effective Tax Rate

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 (benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.

Our effective income tax rates on continuing operations for the first nine months of 2015 and 2014 were 28% and 32%.  The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first nine months of 2015 and 2014.  Excluding Libya, the effective tax rates on continuing operations, would be 27% and 32% for the first nine months of 2015 and 2014. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability.  Thus, for the first nine months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).

Change in Tax Law

On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.

Indefinite Reinvestment Assertion

In the second quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

approximately $1 billion associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes were recorded in the second quarter of 2015.

Deferred Tax Assets

In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

10.    Short-term Investments

As of September 30, 2015, our short-term investments are comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values of our short-term investments approximate fair value. These short-term investments matured during October 2015.

11.   Inventories

 Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.

	September 30,		December 31,
(In millions)	2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	39	$	58
Supplies and other items	285		299
Inventories, at cost	$	324	$	357

12.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization

	September 30,		December 31,
(In millions)	2015		2014
North America E&P	$	15,875	$	16,717
International E&P	2,604		2,741
Oil Sands Mining	9,334		9,455
Corporate	107		127
Net property, plant and equipment	$	27,920	$	29,040

Our Libya operations continue to be impacted by civil unrest and, in December 2014, Libya’s National Oil Corporation once again declared force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.

As of September 30, 2015, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million boe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $775 million by a material amount.

Exploratory well costs capitalized greater than one year after completion of drilling were $88 million and $126 million as of September 30, 2015 and December 31, 2014. This $38 million net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage demonstration project at Birchwood.

13. Other Noncurrent Assets

	September 30,		December 31,
(in millions)	2015		2014
Deferred tax assets	$	1,115	$	525
Intangible assets	95		96
Other	217		185
Other noncurrent assets	$	1,427	$	806

14. Impairments and Exploration Expenses

The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.

The following table summarizes impairment charges of proved properties:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2015		2014		2015		2014
Total impairments	$	337	$	109	$	381	$	130

Impairments for the three and nine months ended September 30, 2015 consisted primarily of proved properties in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices.

Impairments for the three and nine months ended September 30, 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Note 7 for relevant detail regarding segment presentation and Note 15 for fair value measurements related to impairments of proved properties.

The following table summarizes the components of exploration expenses:

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Exploration Expenses
Unproved property impairments	$	563		$	39	$	612	$	140
Dry well costs	(3		)	25		96		80
Geological and geophysical	8			10		23		27
Other	17			22		55		67
Total exploration expenses	$	585		$	96	$	786	$	314

Included in the unproved property impairments for the three and nine months ended September 30, 2015 are non-cash charges of $553 million as a result of changes in our conventional exploration strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).

Unproved property impairments for the three and nine months ended September 30, 2014 primarily consist of leases in Texas and North Dakota that either expired or we decided not to drill or extend. See Note 7 for relevant detail regarding segment presentation.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15.  Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 by fair value hierarchy level.

	September 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity (a)	$	—	$	61	$	—	$	61
Interest rate	—		15		—		15
Derivative instruments, assets	$	—	$	76	$	—	$	76
Derivative instruments, liabilities
Commodity (a)	$	—	$	3	$	—	$	3
Derivative instruments, liabilities	$	—	$	3	$	—	$	3

^(a) Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8
Derivative instruments, assets	$	—	$	8	$	—	$	8

Commodity derivatives include three-way collars, swaptions, extendable three-way collars and call options. These instruments are measured at fair value using either the Black-Scholes Model or Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 16 for additional discussion of the types of derivative instruments we use.

Fair Values - Nonrecurring

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

	Three Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	41	$	337	$	43	$	109

	Nine Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	58	$	381	$	43	$	130

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. The prolonged decline in commodity prices, and the resulting change in management's future commodity price assumptions, was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future. Long-lived assets held for use that were impaired are discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs, unless otherwise noted.  Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

2015 - North America E&P

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

    During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale (see Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model.

2015 - International E&P

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

2014 - North America E&P

The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first nine months of 2014, we recorded additional impairments of $30 million as a result of estimated abandonment cost revisions.

In the third quarter of 2014, impairments of $53 million were recorded to certain other Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two additional on-shore fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.

Fair Values – Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Fair Values – Financial Instruments

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	109	$	116	$	132	$	129
Total financial assets	109		116		132		129
Financial liabilities
Other current liabilities	15		14		13		13
Long-term debt, including current portion (a)	8,302		8,324		6,887		6,360
Deferred credits and other liabilities	69		64		69		68
Total financial liabilities	$	8,386	$	8,402	$	6,969	$	6,441

^(a)    Excludes capital leases.

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

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

16. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 15. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets as of September 30, 2015 and December 31, 2014.

	September 30, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	15	$	—	$	15	Other noncurrent assets
Total Designated Hedges	15		—		15
Not Designated as Hedges
Commodity	55		2		53		Other current assets
Commodity	6		1		5		Other noncurrent assets
Total Not Designated as Hedges	61		3		58
Total	$	76	$	3	$	73

	December 31, 2014
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Total	$	8	$	—	$	8

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Fair Value Hedges

The following table presents, by maturity date, information about our interest rate swap agreements as of September 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

	September 30, 2015				December 31, 2014
	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	4.68	%	$	600	4.64	%
March 15, 2018	$	300	4.54	%	$	300	4.49	%

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.

		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other	$	4		$	(6	)	$	7		$	(3	)
Foreign currency	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	(4	)	$	6		$	(7	)	$	3
Accrued taxes	Discontinued operations	$	—		$	18		$	—		$	29

Derivatives not Designated as Hedges

During the first nine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives consist of three-way collars, extendable three-way collars and call options. Three way-collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract crude oil volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges and are shown in the table below:

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29
Ceiling	$60.00	2,000	October 2015- March 2016 (a)
Floor	$50.00
Sold put	$40.00
Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00
Ceiling	$73.13	2,000	January- June 2016 (b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 (c)

^(a)  Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(b)  Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(c)  Call options settle monthly.

The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net gain of $108 million and $91 million in the third quarter and first nine months2015. There were no crude oil derivative instruments in the first nine months of 2014.

On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 18). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.

17.    Incentive Based Compensation

Stock option and restricted stock awards

  The following table presents a summary of stock option and restricted stock award activity for the first nine months of 2015: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014	13,427,836				$29.68	3,448,353			$34.04
Granted	724,082		(a)		$29.06	2,674,987			$30.52
Options Exercised/Stock Vested	(549,926	)			$16.84	(1,135,635	)		$33.25
Canceled	(605,760	)			$34.11	(708,380	)		$33.20
Outstanding at September 30, 2015	12,996,232				$29.99	4,279,325			$32.17

^(a)    The weighted average grant date fair value of stock option awards granted was $6.84 per share.

Stock-based performance unit awards

 During the first nine months of 2015, we granted 382,335 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

18.  Debt

Revolving Credit Facility As of September 30, 2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described below.

In May 2015, we amended our $2.5 billion unsecured Credit Facility to increase the facility size by $500 million to a total of $3 billion and extended the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.

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 September 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 30%.

Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:

•$600 million of 2.70% senior notes due June 1, 2020

•$900 million of 3.85% senior notes due June 1, 2025

•$500 million of 5.20% senior notes due June 1, 2045

Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes. As of September 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.

19.  Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative
Net settlement loss	(18		)	(22		)	(99		)	(93		)	General and administrative
Net curtailment gain (loss)	(4		)	—			(1		)	—			General and administrative
	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations
	10			10			44			38			Benefit for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(18	)	$	(19	)	$	(76	)	$	(79	)	Income (loss) from continuing operations

20

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

20.  Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2015			2014
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(200	)	$	(201	)
Income taxes paid to taxing authorities (a)	(174		)	(1,514		)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances	$	—		$	2,285
Repayments	—			(2,420		)
Commercial paper, net	$	—		$	(135	)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized, net of revisions	$	12		$	240
Asset retirement obligations assumed by buyer	23			52
Receivable for disposal of assets	—			44

^(a)  The first nine months of 2014 included $1,195 million related to discontinued operations.

21.   Commitments and Contingencies

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

21

Item 2. 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 preceding consolidated financial statements and notes in Item 1.

Executive Overview

We are an independent global exploration and production company based in Houston, Texas. Our operations are primarily located in North America, Europe and Africa with a focus on our North American unconventional shale plays. Total proved reserves were 2.2 billion boe at December 31, 2014 and total assets were $35 billion at September 30, 2015.

Our significant financial results, operating activities and strategic actions include the following:

• Increased company-wide net sales volumes from continuing operations by 7% to 445 mboed in the third quarter of 2015 from 417 mboed in the third quarter of 2014

◦ Net sales volumes from our three U.S. resource plays increased 9% to 210 mboed in the third quarter of 2015 from 192 mboed in the third quarter of 2014

• Maintained focus on cost discipline and efficiencies

◦ Reduced third quarter cash capital expenditures to $628 million, a 28% decrease compared to the previous quarter, reflecting continued capital discipline and benefits from operating efficiencies

◦ Reduced company-wide production expenses per boe in the third quarter of 2015 compared to the same period last year

▪ North America E&P - 27% reduction to $7.43 per boe

▪ International E&P - 47% reduction to $5.53 per boe

▪ Oil Sands Mining - 30% reduction to $26.01 per boe

◦ Achieved 97% average operational availability for our operated assets in the third quarter of 2015

• Active management of liquidity and capital structure

◦ At the end of the third quarter, we had $5.4 billion of liquidity, including $2.4 billion in cash and short-term investments, $1 billion of which was used to repay our senior notes that matured in November

◦ Cash and short-term investments-adjusted debt-to-capital ratio of 24% at September 30, 2015, as compared with 16% at December 31, 2014

• Portfolio management activities

◦ We continue to make progress advancing our goal to divest at least $500 million of non-core asset sales

▪ Closed on the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in August 2015 for proceeds of approximately $100 million

▪ Signed agreement for sale of our East Africa exploration acreage

•Financial results

◦ Loss from continuing operations per diluted share of $1.11 in the third quarter of 2015 as compared to income from continuing operations of $0.45 per diluted share in the same period last year

◦ Included in the loss for the third quarter are $611 million ($949 million pre-tax) of non-cash charges comprised largely of losses and asset impairments resulting from lower forecasted commodity prices and changes in our conventional exploration strategy (refer to Exploration Update below)

◦ Operating cash flow provided by continuing operations for the first nine months of 2015 was $1.2 billion, compared to $3.5 billion in the same period last year, reflecting the lower commodity price environment

Subsequent to the end of the third quarter, we reduced our quarterly dividend from $0.21 to $0.05 per share to address the uncertainty of a lower for longer commodity price environment, to align with our priority of maintaining a strong balance sheet through the cycle and to provide us with additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.

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Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. We believe we can manage in this lower commodity price cycle through a continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.

We expect our full-year 2015 capital, investment and exploration budget to be $3.1 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 380 - 390 net mboed and OSM's synthetic crude oil production to be 40 - 45 net mboed. In addition, based on our current outlook and preliminary plan discussions, we would anticipate a 2016 capital, investment and exploration program of up to $2.2 billion which would give us the flexibility to deliver 2016 annual average production in the U.S. resource plays flat to the 2015 exit rate.

Exploration Update

In September 2015, we announced our intention to scale back our conventional exploration program with an anticipated 2016 program of approximately $100 million, a reduction of 60% as compared to the 2015 budget, subject to approval by our Board of Directors.  Our conventional exploration focus will be redirected to existing commitments in the Gulf of Mexico and Gabon.  As a result, we recorded non-cash impairments related to unproved properties in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq in the third quarter.

Operations

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

	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
North America E&P (mboed)	261	250	4%	273	230	19%
International E&P (mboed)	119	112	6%	115	121	(5)%
Oil Sands Mining (mbbld) (a)	65	55	18%	51	49	4%
Total Continuing Operations (mboed)	445	417	7%	439	400	10%

^(a)    Includes blendstocks

North America E&P--Net Sales Volumes

Net sales volumes in the North America E&P segment increased as a result of continued growth from the combined U.S. resource plays. The following table provides net sales volumes for our significant operational areas within this segment.

	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	126	117	8%	137	105	30%
Oklahoma Resource Basins	23	19	21%	24	17	41%
Bakken	61	56	9%	59	50	18%
Other North America (a)	51	58	(12)%	53	58	(9)%
Total North America E&P	261	250	4%	273	230	19%

^(a)   Includes Gulf of Mexico and other conventional onshore U.S. production.

The following table provides our sales mix for each of our U.S. resource plays.

	Three Months Ended September 30,
	2015
	Eagle Ford	Oklahoma Resource Basins	Bakken
Crude oil and condensate	59%	18%	87%
Natural gas liquids	20%	28%	8%
Natural gas	21%	54%	5%

The following table presents a summary of our operated drilling activity in the U.S. resource plays:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Gross Operated
Eagle Ford:
Wells drilled to total depth	51	93	198	264
Wells brought to sales	57	87	200	212
Oklahoma Resource Basins:
Wells drilled to total depth	4	4	17	15
Wells brought to sales	8	6	16	14
Bakken:
Wells drilled to total depth	5	25	30	60
Wells brought to sales	5	18	51	52

• Eagle Ford – Of the 57 gross wells brought to sales during this quarter, 11 were in the Austin Chalk, 6 were in the Upper Eagle Ford, and 40 in the Lower Eagle Ford. Our average time to drill an Eagle Ford well in the third quarter2015, spud-to-total depth, decreased to 10 days.

• Oklahoma Resource Basins – During the third quarter, we spud our first Springer well and brought online 8 operated wells (6 in SCOOP and 2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to the 8 wells mentioned above, we completed an additional Smith infill pilot well in the SCOOP which was brought to sales on October 1. These wells are all in the very early stages of production. We continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 55-70 gross outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas, with 17 outside-operated wells brought to sales during the quarter.

• Bakken – The 5 gross wells brought to sales this quarter were in the East Myrmidon area. Despite the lower number of wells to sales this quarter, sales volumes were driven by continued strong performance from the Doll pad wells (West Myrmidon) which came online in late June as well as sustained improvement in production uptime. We expect reduced completions activity during the fourth quarter.

• Gulf of Mexico – Development work continues in the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete by the end of 2015 with first oil in mid-2016. We hold an 18% non-operated working interest in the Gunflint field.

North America E&P--Exploration

• Gulf of Mexico – The third appraisal well on the Shenandoah prospect was spud in May 2015 and reached total depth in October, finding more than 620 feet of net oil pay. The operator completed logging operations and will obtain a whole core across the reservoir interval. The well is located in Walker Ridge Block 51, in which we hold a 10% non-operated working interest. The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of 2015 and is expected to reach total depth in the fourth quarter. We hold a 58% operated working interest in this prospect.

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International E&P--Net Sales Volumes

The following table provides net sales volumes for our significant operational areas within this segment.

	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Net Sales Volumes
Equivalent Barrels (mboed)
Equatorial Guinea	101	97	4%	96	104	(8)%
United Kingdom(a)	18	9	100%	19	15	27%
Libya	—	6	(100)%	—	2	(100)%
Total International E&P (mboed)	119	112	6%	115	121	(5)%
Net Sales Volumes of Equity Method Investees
LNG (mtd)	5,700	6,265	(9)%	5,653	6,488	(13)%
Methanol (mtd)	1,125	1,103	2%	895	1,078	(17)%

^(a)  Includes natural gas acquired for injection and subsequent resale of 8 mmcfd and 3 mmcfd for the third quarters of 2015 and 2014, and 8 mmcfd and 5 mmcfd for the first nine months of 2015 and 2014.

• Equatorial Guinea – Third quarter net sales volumes increased as production from the Alba C21 development well came online with higher than expected yields, combined with a successful wire-line intervention program on five existing Alba wells. The ongoing Alba field compression project, designed to maintain the production plateau two additional years and extend field life up to eight years, achieved mechanical completion at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.

• United Kingdom – Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during 2015. Overall, operating availability was higher for all U.K. assets in 2015 as compared to comparative 2014 periods which included planned and unplanned maintenance activities. During the third quarter of 2015, planned maintenance activities were completed at the East Brae field and continue at the non-operated Foinaven field. The activity at Foinaven will impact production volumes during the fourth quarter of 2015.

• Libya – We had no sales during the first nine months of 2015 as a result of continued civil unrest, as compared to one lifting in the third quarter of 2014. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil terminal. Considerable uncertainty remains around the timing of future production and sales levels.

Oil Sands Mining

 Our net synthetic crude oil sales volumes were 65 mbbld and 51 mbbld in the third quarter and first nine months of2015 compared to 55 mbbld and 49 mbbld in the same periods of 2014. Net sales volumes increased in the third quarter of 2015 primarily due to improved mine reliability and no major maintenance activities. Planned maintenance at both mines in the fourth quarter of 2015 is expected to impact production. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project. 

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Market Conditions

Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were significantly lower in the third quarter and first nine months of 2015 as compared to the same periods in 2014; as a result, we experienced significant declines in our price realizations associated with those benchmarks. 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.

North America E&P

 The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the third quarter and first nine months of2015 and 2014.

	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Decrease	2015	2014	Decrease
Average Price Realizations (a)
Crude Oil and Condensate (per bbl) (b)	$41.37	$89.65	(54)%	$45.27	$92.59	(51)%
Natural Gas Liquids (per bbl)	11.88	33.93	(65)%	13.67	36.96	(63)%
Total Liquid Hydrocarbons (per bbl)	35.75	80.89	(56)%	39.55	83.89	(53)%
Natural Gas (per mcf)	2.75	4.21	(35)%	2.84	4.81	(41)%
Benchmarks
WTI crude oil (per bbl)	$46.50	$97.25	(52)%	$51.01	$99.62	(49)%
LLS crude oil (per bbl)	50.22	101.03	(50)%	55.33	103.63	(47)%
Mont Belvieu NGLs (per bbl) (c)	15.86	32.69	(51)%	17.28	35.15	(51)%
Henry Hub natural gas (per mmbtu)	2.77	4.06	(32)%	2.80	4.55	(38)%

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

^(b)  Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realization by $1.87 per bbl and $0.69 per bbl for the third quarter and first nine months of 2015. There were no crude oil derivative instruments in 2014.

^(c)  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 NGL 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, NGLs, and natural gas for the third quarter and first nine months of2015 and 2014.

	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$46.18	$89.07	(48)%	$50.51	$95.71	(47)%
Natural Gas Liquids (per bbl)	2.69	1.00	169%	3.08	2.83	9%
Liquid Hydrocarbons (per bbl)	35.88	66.80	(46)%	39.21	72.88	(46)%
Natural Gas (per mcf)	0.59	0.56	5%	0.71	0.73	(3)%
Benchmark
Brent (Europe) crude oil (per bbl)(a)	$50.23	$101.82	(51%)	$55.28	$106.56	(48%)

^(a)  Average of monthly prices obtained from EIA website.

Liquid hydrocarbons – Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial Guinea is condensate, which receives lower prices than crude oil.

26

Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are sold to our equity method investees under fixed-price, term contracts; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs and natural gas 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.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily WCS.

The following table presents our average price realizations and the related benchmarks for the third quarter and first nine months of2015 and 2014.

	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Decrease	2015	2014	Decrease
Average Price Realizations
Synthetic Crude Oil (per bbl)	$39.49	$88.22	(55%)	$42.26	$90.11	(53%)
Benchmarks
WTI crude oil(per bbl)	$46.50	$97.25	(52%)	$51.01	$99.62	(49%)
WCS crude oil(per bbl)(a)	33.16	76.99	(57%)	37.80	78.50	(52%)

^(a)  Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

27

Results of Operations

Three Months Ended September 30, 2015 vs. Three Months Ended September 30, 2014

Sales and other operating revenues, including related party are presented by segment in the table below:

	Three Months Ended September 30,
(In millions)	2015		2014
Sales and other operating revenues, including related party
North America E&P	$	796	$	1,586
International E&P	182		273
Oil Sands Mining	242		457
Segment sales and other operating revenues, including related party	$	1,220	$	2,316
Unrealized gain on crude oil derivative instruments	80		—
Sales and other operating revenues, including related party	$	1,300	$	2,316

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.

	Three Months Ended			Increase (Decrease) Related to					Three Months Ended
(In millions)	September 30, 2014			Price Realizations			Net Sales Volumes		September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	1,464		$	(850	)	$	60	$	674
Natural gas	123			(45		)	7		85
Realized gain on crude oil
derivative instruments	—			28					28
Other sales	(1		)						9
Total	$	1,586							$	796
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	240		$	(130	)	$	42	$	152
Natural gas	22			2			—		24
Other sales	11								6
Total	$	273							$	182
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	445		$	(294	)	$	85	$	236
Other sales	12								6
Total	$	457							$	242

Marketing revenuesdecreased$470 million in the third quarter of 2015 from the comparable prior-year period. 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 related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.

Income from equity method investmentsdecreased $53 million in the third quarter of 2015 from the comparable 2014 period. The decrease is primarily due to lower price realizations for LPG at our Alba plant, LNG at our LNG facility, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also impacting the quarter was a partial impairment of our investment in an equity method investee.

Production expensesdecreased$187 million. North America E&P declined $54 million due to lower operational, maintenance and labor costs. International E&P declined $47 million primarily the result of higher project costs in 2014, such as the non-operated Foinaven subsea power project. Also contributing were lower production costs in Libya during 2015 as the third quarter of 2014 had one lifting. OSM decreased $86 million primarily due to continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian Dollar and lower feedstock purchases given increased reliability.

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The third quarter of 2015 production expense rate (expense per boe) for North America E&P declined due to overall cost reductions, as previously discussed, and leveraging efficiencies as production volumes increased. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in Libya. The OSM expense rate decreased as production volume increased, coupled with the increased cost focus discussed above.

The following table provides production expense rates for each segment:

	Three Months Ended September 30,
($ per boe)	2015	2014
Production Expense Rate
North America E&P	$7.43	$10.16
International E&P	$5.53	$10.48
Oil Sands Mining (a)	$26.01	$37.38

^(a)  Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.

Marketing costsdecreased$470 million in the third quarter of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.

Exploration expensesincreased $489 million. We made a strategic decision to reduce the overall level of our conventional exploration program; as a result, we impaired certain of our leases in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq. Further contributing to the increase was an impairment of unproved property in Colorado, which we deemed uneconomic given our forecasted natural gas prices. The following table summarizes the components of exploration expenses:

	Three Months Ended September 30,
(In millions)	2015			2014
Exploration Expenses
Unproved property impairments	$	563		$	39
Dry well costs	(3		)	25
Geological and geophysical	8			10
Other	17			22
Total exploration expenses	$	585		$	96

Depreciation, depletion and amortization(“DD&A”) decreased$20 million primarily as a result of a higher proved reserve base in Eagle Ford, the effects of which more than offset additional DD&A resulting from production volume increases in the International E&P and OSM segments. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, proved 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 North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford. The International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program.

	Three Months Ended September 30,
($ per boe)	2015		2014
DD&A Rate
North America E&P		$22.84		$26.54
International E&P		$7.32		$5.30
Oil Sands Mining		$12.62		$12.75

Impairments are discussed in Note 14 to the consolidated financial statements.

29

Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $69 million in the third quarter of 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:

	Three Months Ended September 30,
(In millions)	2015		2014
Production and severance	$	28	$	69
Ad valorem	2		20
Other	16		26
Total	$	46	$	115

General and administrative expensesdecreased$35 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. Pension settlement charges in the three months of 2015 totaled $18 million compared to $22 million in the prior year. In addition, we incurred severance related expenses in the first three months of 2015 associated with workforce reductions of $4 million.

Provision (benefit) for income taxes reflects an effective tax rate of 35% in the third quarter of 2015, as compared to 33% in the third quarter of 2014. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.

Segment Income(Loss)

Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. 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 crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

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

	Three Months Ended September 30,
(In millions)	2015			2014
North America E&P	$	(61	)	$	292
International E&P	29			106
Oil Sands Mining	(11		)	93
Segment income (loss)	(43		)	491
Items not allocated to segments, net of income taxes	(706		)	(187		)
Income (loss) from continuing operations	(749		)	304
Discontinued operations (a)	—			127
Net income (loss)	$	(749	)	$	431

^(a)  As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.

 North America E&P segment income (loss) decreased $353 million after-tax primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays and lower production and operating costs.

International E&P segment incomedecreased $77 million after-tax primarily due to lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by increased sales volumes and lower production and exploration expenses.

Oil Sands Mining segment income (loss)decreased $104 million after-tax primarily due to lower price realizations, partially offset by higher volumes and reduced production expenses.

30

Results of Operations

Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014

Sales and other operating revenues, including related party are presented by segment in the table below:

	Nine Months Ended September 30,
(In millions)	2015		2014
Sales and other operating revenues, including related party
North America E&P	$	2,639	$	4,518
International E&P	575		1,000
Oil Sands Mining	614		1,217
Segment sales and other operating revenues, including related party	$	3,828	$	6,735
Unrealized gain on crude oil derivative instruments	59		—
Sales and other operating revenues, including related party	$	3,887	$	6,735

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.

	Nine Months Ended		Increase (Decrease) Related to						Nine Months Ended
(In millions)	September 30, 2014		Price Realizations			Net Sales Volumes			September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	4,112	$	(2,586	)	$	781		$	2,307
Natural gas	398		(190		)	65			273
Realized gain on crude oil
derivative instruments	—		33						33
Other sales	8								26
Total	$	4,518							$	2,639
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	873	$	(396	)	$	(15	)	$	462
Natural gas	92		(2		)	(7		)	83
Other sales	35								30
Total	$	1,000							$	575
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	1,195	$	(672	)	$	69		$	592
Other sales	22								22
Total	$	1,217							$	614

Marketing revenuesdecreased$1,242 million. 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 related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.

Income from equity method investmentsdecreased$248 million primarily due to lower price realizations for LPG at our Alba Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to the decrease in 2015 were lower sales volumes due to the planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.

Production expenses for the first nine months of 2015 decreased by $397 million. North America E&P declined $101 million due to lower operational, maintenance and labor costs. International E&P declined $115 million due to lower project work, repair, maintenance and turnaround costs as well as slightly lower production volumes. OSM declined $181 million primarily due to continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease are lower feedstock purchases given increased reliability and a more favorable exchange rate on expenses denominated in the Canadian Dollar.

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The expense rates during the first nine months of 2015 decreased for each of our segments as total production costs declined due to the reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume increases, which further contributed to the expense rate decline. The following table provides production expense rates for each segment:

	Nine Months Ended September 30,
($ per boe)	2015		2014
Production Expense Rate
North America E&P		$7.52		$10.52
International E&P		$6.13		$9.34
Oil Sands Mining (a)		$39.58		$44.73

^(a)  Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.

Marketing costsdecreased$1,239 million in the first nine months of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.

Exploration expensesincreasedby$472 million as a result of unproved property impairments recognized during the third quarter of 2015. See the preceding three month period discussion for further information on our unproved property impairments. Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs for the first nine months of 2015 include the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood in-situ that were expensed during the second quarter of 2015. Dry well costs for the first nine months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya. The following table summarizes the components of exploration expenses:

	Nine Months Ended September 30,
(In millions)	2015		2014
Exploration Expenses
Unproved property impairments	$	612	$	140
Dry well costs	96		80
Geological and geophysical	23		27
Other	55		67
Total exploration expenses	$	786	$	314

Depreciation, depletion and amortization(“DD&A”) increased $229 million primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, proved reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment.

	Nine Months Ended September 30,
($ per boe)	2015		2014
DD&A Rate
North America E&P		$25.09		$26.65
International E&P		$6.87		$6.09
Oil Sands Mining		$12.60		$12.14

Impairments are discussed in Note 14 to the consolidated financial statements.

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Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $128 million in the first nine months of 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:

	Nine Months Ended September 30,
(In millions)	2015		2014
Production and severance	$	102	$	191
Ad valorem	33		58
Other	56		70
Total	$	191	$	319

General and administrative expensesdecreased$22 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. This decrease was partially offset by $47 million of severance related expenses. The first nine months of 2015 include $99 million of pension settlement expense as compared to $93 million for the previous year.

Provision (benefit) for income taxes reflects an effective tax rate of 28% in the first nine months of 2015, as compared to 32% in the comparable 2014 period. The effective rate for 2015 reflects a $135 million non-cash deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.

Segment Income(Loss)

Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

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

	Nine Months Ended September 30,
(In millions)	2015			2014
North America E&P	$	(267	)	$	836
International E&P	93			487
Oil Sands Mining	(107		)	212
Segment income (loss)	(281		)	1,535
Items not allocated to segments, net of income taxes	(1,130		)	(473		)
Income (loss) from continuing operations	(1,411		)	1,062
Discontinued operations (a)	—			1,058
Net income (loss)	$	(1,411	)	$	2,120

^(a)  As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.

 North America E&P segment income (loss) decreased $1,103 million after-tax in the first nine months of 2015 primarily due to lower price realizations; these were partially offset by increased net sales volumes from the U.S. resource plays and lower production costs.

International E&P segment incomedecreased $394 million after-tax primarily due to lower liquid hydrocarbon price realizations and reduced income from equity investments. These declines were partially offset by lower production and exploration expenses.

Oil Sands Mining segment income (loss)decreased $319 million after-tax primarily due to lower price realizations, partially offset by reduced production expenses.

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Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2014, except as discussed below.

Fair Value Estimates - Impairment Assessments of Long-Lived Assets and Goodwill

The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. We estimated the fair values using an income approach and concluded that impairments of $337 million were required (See Notes 14 & 15 ). Changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision to forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Income Tax Estimates - Deferred Tax Assets

In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

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Cash Flows and Liquidity

 Cash Flows

 The following table presents sources and uses of cash and cash equivalents

	Nine Months Ended September 30,
(In millions)	2015			2014
Sources of cash and cash equivalents
Operating activities of continued operations	$	1,213		$	3,476
Operating activities of discontinued operations	—			856
Borrowings	1,996			—
Disposals of assets	105			2,237
Maturities of short-term investments	225			—
Other	97			196
Total sources of cash and cash equivalents	$	3,636		$	6,765
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(2,948	)	$	(3,639	)
Investing activities of discontinued operations	—			(356		)
Purchases of short-term investments	(925		)	—
Debt issuance costs	(19		)	—
Debt repayments	(34		)	(34		)
Dividends paid	(427		)	(401		)
Purchases of common stock	—			(1,000		)
Commercial paper, net	—			(135		)
Other	(1		)	(48		)
Cash held for sale	—			(655		)
Total uses of cash and cash equivalents	$	(4,354	)	$	(6,268	)

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. This lower price trend adversely impacted our cash flows in 2015. Partially offsetting the decline in prices were increased net sales volumes in the North America E&P and OSM segments. While we are unable to predict future commodity price movements, if this lower price environment continues, it would continue to negatively impact our cash flows from operating activities as compared to the previous year.

Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. See Liquidity and Capital Resources below for additional information.

Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposal of assets in 2015 pertain to the August 2015 sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. Disposals of assets in 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 6 to the consolidated financial statements.

In October, 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.

Certain of our short-term investments matured in September 2015. Purchases of short-term investments in 2015 were made from proceeds received from the senior notes issuance in June 2015. The investments consisted of time deposits with maturity dates ranging from September - October 2015.

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Additions to property, plant and equipment are our most significant use of cash and cash equivalents. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash flows:

	Nine Months Ended September 30,
(In millions)	2015		2014
North America E&P	$	2,048	$	3,246
International E&P	275		386
Oil Sands Mining	26		172
Corporate	26		29
Total capital expenditures	2,375		3,833
(Increase) decrease in capital expenditure accrual	573		(194		)
Total use of cash and cash equivalents for property, plant and equipment	$	2,948	$	3,639

During the first nine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program. There were no stock repurchases during 2015.

Liquidity and Capital Resources

On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:

•$600 million of 2.70% senior notes due June 1, 2020

•$900 million of 3.85% senior notes due June 1, 2025

•$500 million of 5.20% senior notes due June 1, 2045

Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We used the aggregate net proceeds to repay our $1 billion 0.90% senior notes on November 2, 2015, and the remainder for general corporate purposes.

In May 2015, we amended our $2.5 billion Credit Facility to increase the facility size by $500 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.

Our main sources of liquidity are cash and cash equivalents, short-term investments, internally generated cash flow from operations, the issuance of notes, our $3 billion Credit Facility and sales of non-core assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our revolving credit facility. Furthermore, we actively manage our capital spending program, including the level and timing of activities associated with our drilling programs. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our liquidity is adequate to fund not only our current operations, but also our funding requirements for the foreseeable future, 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.

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Capital Resources

Credit Arrangements and Borrowings

At September 30, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

At September 30, 2015, we had $8.4 billion in long-term debt outstanding, of which approximately $1.0 billion matured and was repaid in November 2015. We utilized cash on hand and proceeds from the maturities of our short-term investments to fund the debt payment. 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 equity and debt securities. 

Asset Disposals

We are targeting to generate at least $500 million from select non-core asset sales. During the third quarter of 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and announced the sale of our Kenya and Ethiopia exploration acreage. See Note 6 to the consolidated financial statements for additional discussion of these dispositions.        

Cash and Short-Term Investments-Adjusted Debt-To-Capital Ratio

 Our cash and short-term investments-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash equivalents and short-term investments) was 24% at September 30, 2015, compared to 16% at December 31, 2014.

	September 30,			December 31,
(In millions)	2015			2014
Long-term debt due within one year	$	1,035		$	1,068
Long-term debt	7,323			5,323
Total debt	$	8,358		$	6,391
Cash and cash equivalents	$	1,680		$	2,398
Short-term investments	$	700		$	—
Equity	$	19,335		$	21,020
Calculation:
Total debt	$	8,358		$	6,391
Minus cash and cash equivalents	1,680			2,398
Minus short-term investments	700			—
Total debt minus cash, cash equivalents and short-term investments	$	5,978		$	3,993
Total debt	$	8,358		$	6,391
Plus equity	19,335			21,020
Minus cash and cash equivalents	1,680			2,398
Minus short-term investments	700			—
Total debt plus equity minus cash, cash equivalents and short-term investments	$	25,313		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio	24		%	16		%

Capital Requirements

We expect our revised total capital, investment and exploration spending budget for full-year 2015 to be $3.1 billion which is $200 million less than our previous budget.

On October 28, 2015, our Board of Directors approved a dividend of $0.05 per share for the third quarter of 2015 payable December 10, 2015 to stockholders of record at the close of business on November 18, 2015. This dividend represents a reduction from the previous quarterly dividend of $0.21 per share as we continue to address the uncertainty of a lower for longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle, and provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.

As of September 30, 2015, we plan to make contributions of up to $18 million to our funded pension plans during the remainder of 2015.

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Contractual Cash Obligations

As of September 30, 2015, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2014 Annual Report on Form 10-K, except for our issuance of $2 billion aggregate principal amount of unsecured senior notes, as more fully described in Note 18.

Environmental Matters

We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.  If these expenditures, as with all costs, are not ultimately 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.

There have been no significant changes to our environmental matters subsequent to December 31, 2014.

Other Contingencies

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

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding: our operational, financial and growth strategies, including planned projects, drilling plans, maintenance activities, asset sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof; our financial and operational outlook and ability to fulfill that outlook; expectations regarding future economic and market conditions and their effects on our business; our 2015 and 2016 capital, investment and exploration programs, including planned allocation and reductions, and the expected benefits thereof; our declared dividend and the expected benefits thereof; our financial position, liquidity and capital resources; production guidance; and the plans and objectives of our management for our future operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “estimate,” “expect,” “target,” “plan,” “project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

• conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;

• changes in expected reserve or production levels;

• changes in political or economic conditions in key operating markets, including international markets;

• capital available for exploration and development;

• well production timing;

• availability of drilling rigs, materials and labor;

• difficulty in obtaining necessary approvals and permits;

• non-performance by third parties of contractual obligations;

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

• cyber-attacks;

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

• other geological, operating and economic considerations; and

• the risk factors, forward-looking statements and challenges and uncertainties described in our 2014 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.

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 or obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2014 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 15 and 16 to the consolidated financial statements.

Commodity Price Risk During the first nine months of 2015, we entered into crude oil derivatives, indexed to NYMEX WTI, related to a portion of our forecasted North America E&P sales. The table below provides a summary of open positions as of September 30, 2015:

Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29
Ceiling	$60.00	2,000	October 2015- March 2016 (a)
Floor	$50.00
Sold put	$40.00
Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00
Ceiling	$73.13	2,000	January- June 2016 (b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 (c)

^(a)  Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(b)  Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(c)  Call options settle monthly.

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 prices on our open commodity derivative instruments as of September 30, 2015.

(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Crude oil commodity derivatives	$	(46	)	$	6

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of September 30, 2015, is provided in the following table.

(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):
Long term debt, including amounts due within one year	$	(8,302	)	(a)(b)	$	(295	)

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

^(b)  Excludes capital leases.

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Item 4. 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 Exchange Act) 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 September 30, 2015.  

During the third quarter of 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

40

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business.  There have been no material changes to the risk factors under Item 1A. Risk Factors in our 2014 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by Marathon Oil during the quarter ended September 30, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.

	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased (a)	Paid per Share	Plans or Programs	Plans or Programs
07/01/15 - 07/31/15	3,333	25.58	—	$1,500,285,529
08/01/15 - 08/31/15	46,543	18.50	—	$1,500,285,529
09/01/15 - 09/30/15	5,444	15.01	—	$1,500,285,529
Total	55,320	18.59	—

^(a)  55,320 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

Item 5. Other Information

As we previously disclosed in a Form 8-K filed with the SEC on August 28, 2015, our Board of Directors amended and restated our By-laws, effective September 1, 2015, to modify the existing proxy access provisions of the By-laws to coincide with the stockholder proposal that was approved at our 2015 annual meeting of stockholders.

Pursuant to these amendments, the required ownership percentage needed to use the proxy access provisions was decreased to 3% of Marathon Oil’s outstanding common stock, owned continuously for at least three years. Additionally, the maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions was increased to 25% of the number of directors in office as of the last day on which notice requesting proxy access may be delivered by an eligible stockholder.

Item 6.  Exhibits

The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.

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SIGNATURES

Pursuant to the requirements 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.

November 5, 2015		MARATHON OIL CORPORATION
	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

42

Exhibit Index

		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date
2.1++	Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	8-K	2.1	5/26/2011
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 September 1, 2015)	8-K	3.1	8/28/2015
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
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 SEC upon its request	10-K	4.1	2/28/2014
12.1	Computation of Ratio of Earnings to Fixed Charges*
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 Executive Vice President and 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 Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS	XBRL Instance Document*
101.SCH	XBRL Taxonomy Extension Schema*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase*
101.DEF	XBRL Taxonomy Extension Definition Linkbase*
101.LAB	XBRL Taxonomy Extension Label Linkbase*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase*
*	Filed herewith.
++	Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

EX-12.1

Exhibit 12.1

MARATHON OIL CORPORATION

Computation of Ratio of Earnings to Fixed Charges (Unaudited)

	Nine Months Ended			Year Ended
	September 30,			December 31,
(In millions)	2015			2014			2013			2012			2011			2010
Income (loss) from continuing operations before income taxes	$	(1,957	)	$	1,361		$	2,393		$	3,104		$	1,615		$	1,674
Income from equity method investments	98			424			423			370			462			344
Income (loss) from continuing operations before income taxes and income from equity method investments	(2,055		)	937			1,970			2,734			1,153			1,330
Add (deduct)
Fixed charges	284			352			360			338			504			573
Capitalized interest	(20		)	(33		)	(27		)	(68		)	(208		)	(410		)
Amortization of capitalized interest	4			8			21			45			107			115
Distributed income from equity investees	139			454			430			382			499			404
Earnings as defined	(1,648		)	1,718			2,754			3,431			2,055			2,012
Net interest expense (including discontinued operations)	236			277			297			236			245			75
Capitalized interest (including discontinued operations)	20			33			27			68			208			410
Interest portion of rental expense (including discontinued operations)	28			42			36			34			51			88
Fixed charges as defined	284			352			360			338			504			573
Ratio of earnings to fixed charges	(5.80		)	4.88			7.65			10.15			4.08			3.51
Amount by which earnings were insufficient to cover fixed charges	$	1,932		$	—		$	—		$	—		$	—		$	—

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-Q 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:	November 5, 2015	/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, John R. Sult, certify that:

1. I have reviewed this report on Form 10-Q 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:	November 5, 2015	/s/ John R. Sult
		John R. Sult
		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 Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2015 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.

November 5, 2015

/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 Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John R. Sult, Executive Vice President and Chief Financial 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.

November 5, 2015

/s/ John R. Sult

John R. Sult

Executive Vice President and Chief Financial Officer

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Incentive Based Compensation (Tables)

9 Months Ended

Sep. 30, 2015

Incentive Based Compensation Plans [Abstract]

Table of Incentive based compensation activity [Table Text Block]

The following table presents a summary of stock option and restricted stock award activity for the first nine months of 2015: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014	13,427,836				$29.68	3,448,353			$34.04
Granted	724,082		(a)		$29.06	2,674,987			$30.52
Options Exercised/Stock Vested	(549,926	)			$16.84	(1,135,635	)		$33.25
Canceled	(605,760	)			$34.11	(708,380	)		$33.20
Outstanding at September 30, 2015	12,996,232				$29.99	4,279,325			$32.17

^(a)    The weighted average grant date fair value of stock option awards granted was $6.84 per share.

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Impairments and Exploration Expenses Impairments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Impairments [Abstract]
Impairment of Oil and Gas Properties	$ 337	$ 109	$ 381	$ 130

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Defined Benefit Postretirement Plans (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension and Other Postretirement Benefit Contributions [Abstract]
Pension Contributions					$ 65
Defined Benefit Plan, Benefits Paid					57
Other Postretirement Benefits Payments					13
Scenario, Forecast [Member]
Pension and Other Postretirement Benefit Contributions [Abstract]
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year		$ 18
United States and Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost			$ 11	$ 12	35	$ 35
Interest cost			12	15	39	46
Expected return on plan assets			(17)	(16)	(53)	(48)
Amortization:
- prior service cost (credit)			(3)	1	(4)	4
-actuarial loss (gain)			5	7	19	23
Net settlement loss	[1]		18	22	99	93
Defined Benefit Plan, Curtailments	[2]		4	0	5	0
Net periodic benefit cost			30	41	140	153
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost			0	0	2	2
Interest cost			3	4	8	10
Expected return on plan assets			0	0	0	0
Amortization:
- prior service cost (credit)			(1)	(1)	(3)	(3)
-actuarial loss (gain)			1	0	1	0
Net settlement loss	[1]		0	0	0	0
Defined Benefit Plan, Curtailments	[2]		0	0	(4)	0
Net periodic benefit cost			$ 3	$ 3	$ 4	$ 9

[1] Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.

[2] 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.

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
Net cash provided by (used in) operating activities included:
Interest paid (net of amounts capitalized)		$ (200)	$ (201)
Income taxes paid to taxing authorities	[1]	(174)	(1,514)
Income Taxes Paid Net, Discontinued Operations			1,195
Commercial paper, net:
Commercial paper - issuances		0	2,285
Commercial paper - repayments		0	(2,420)
Commercial paper, net		0	(135)
Noncash investing activities:
Asset retirement costs capitalized		12	240
Asset retirement obligations assumed by buyer		23	52
Receivable Related To Disposal Of Assets		$ 0	$ 44

[1] The first nine months of 2014 included $1,195 million related to discontinued operations.

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Impairments and Exploration Expenses Exploration Expenses (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014	Sep. 30, 2015		Sep. 30, 2014
Exploration Expenses [Line Items]
Exploration Expenses	$ 585		$ 96	$ 786		$ 314
Corporate and Other [Member]
Exploration Expenses [Line Items]
Exploration Expenses	553	[1]	0	553	[1]	0
Unproved Property Impairments [Member]
Exploration Expenses [Line Items]
Exploration Expenses	563		39	612		140
Dry Well Costs [Member]
Exploration Expenses [Line Items]
Exploration Expenses	(3)		25	96		80
Geological and Geophysical [Member]
Exploration Expenses [Line Items]
Exploration Expenses	8		10	23		27
Other Exploration Expenses [Member]
Exploration Expenses [Line Items]
Exploration Expenses	$ 17		$ 22	$ 55		$ 67

[1] Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

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Dispositions Dispositions - Discontinued Ops (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 105	$ 2,237
NORWAY
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue	$ 528			1,901
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, before Income Tax	487			1,617
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	$ 127			449	[1]
ANGOLA
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest Percentage		10.00%
Proceeds from Sale of Oil and Gas Property and Equipment		$ 2,000
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		$ 576
Disposal Group, Including Discontinued Operation, Revenue				58
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, before Income Tax				51
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax				470
Discontinued Operations, Income (Loss) from Discontinued Operations During Phase-out Period Plus Gain (Loss) from Disposal, Net of Tax				$ 609

[1] Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.

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Inventories (Tables)

9 Months Ended

Sep. 30, 2015

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.

	September 30,		December 31,
(In millions)	2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	39	$	58
Supplies and other items	285		299
Inventories, at cost	$	324	$	357

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Fair Value Measurements (Details 2-Nonrecurring) - Fair Value, Measurements, Nonrecurring [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure, Quarter to Date	$ 41	$ 43	$ 41	$ 43
Assets, Fair Value Adjustment	337	109	381	130
Property, Plant, and Equipment, Fair Value Disclosure	58	43	58	43
Colorado Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	41		41
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		$ 604
Gulf of Mexico Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		19		19
Other Domestic Fields [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		24		24
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]
Assets, Fair Value Adjustment	333
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, Inputs, Level 3 [Member] | EG Equity Method Investment [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Assets, Fair Value Adjustment	$ 12
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				$ 30
Fair Value, Inputs, Level 3 [Member] | Gulf of Mexico Assets [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Assets, Fair Value Adjustment		53
Fair Value, Inputs, Level 3 [Member] | Other Domestic Fields [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Assets, Fair Value Adjustment		$ 47

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Reclassifications out of Accumulated Other Comprehensive Income

9 Months Ended

Sep. 30, 2015

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassifications Out of Accumulated Other Comprehensive Loss

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative
Net settlement loss	(18		)	(22		)	(99		)	(93		)	General and administrative
Net curtailment gain (loss)	(4		)	—			(1		)	—			General and administrative
	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations
	10			10			44			38			Benefit for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(18	)	$	(19	)	$	(76	)	$	(79	)	Income (loss) from continuing operations

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Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Liquid hydrocarbons natural gas and bitumen	$ 39	$ 58
Supplies and other items	285	299
Total inventories, at cost	$ 324	$ 357

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Variable Interest Entity (Details) - Variable Interest Entity, Not Primary Beneficiary [Member] - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	20.00%
Recorded liability related to unconsolidated VIE	$ 2	$ 3
Maximum exposure to loss related to unconsolidated VIE	$ 471

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 by fair value hierarchy level.

	September 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity (a)	$	—	$	61	$	—	$	61
Interest rate	—		15		—		15
Derivative instruments, assets	$	—	$	76	$	—	$	76
Derivative instruments, liabilities
Commodity (a)	$	—	$	3	$	—	$	3
Derivative instruments, liabilities	$	—	$	3	$	—	$	3

^(a) Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8
Derivative instruments, assets	$	—	$	8	$	—	$	8

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]

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.

	Three Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	41	$	337	$	43	$	109

	Nine Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	58	$	381	$	43	$	130

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	109	$	116	$	132	$	129
Total financial assets	109		116		132		129
Financial liabilities
Other current liabilities	15		14		13		13
Long-term debt, including current portion (a)	8,302		8,324		6,887		6,360
Deferred credits and other liabilities	69		64		69		68
Total financial liabilities	$	8,386	$	8,402	$	6,969	$	6,441

^(a)    Excludes capital leases.

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Property, Plant and Equipment Property, Plant and Equipment (Details 2) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year After Completion of Drilling	$ 88	$ 126
Capitalized Exploratory Well Cost, Period Increase (Decrease)	$ (38)

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Debt - Revolving Credit Facility (Details)	Sep. 30, 2015	May. 31, 2015 USD ($)	Apr. 30, 2015 USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, maximum borrowing capacity		$ 3,000,000,000	$ 2,500,000,000.0
Line of Credit Facility, increase in borrowing capacity		500,000,000
Line of credit, extended borrowing capacity		500,000,000
Ratio of indebtedness to net capital	0.30
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, maximum borrowing capacity		500,000,000
Bridge Loan [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, maximum borrowing capacity		$ 100,000,000
Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of indebtedness to net capital		0.65

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Derivatives (Details 3-Fair Value Hedges IS & OCI) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net			$ 0	$ 0
Net interest and other [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	$ (4)	$ 6	(7)	3
Discontinued Operations [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	0	18	0	29
Interest rate [Member] | Net interest and other [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments recognized in income	4	(6)	7	(3)
Foreign Exchange Contract [Member] | Discontinued Operations [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments recognized in income	$ 0	$ (18)	$ 0	$ (29)

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Segment Information (Details) - USD ($) $ in Millions		3 Months Ended					9 Months Ended
		Sep. 30, 2015		Jun. 30, 2015	Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Segment Reporting Information [Line Items]
Sales and other operating revenues		$ 1,300			$ 2,316		$ 3,887		$ 6,735
Marketing revenues		84			554		471		1,713
Total revenues		1,384			2,870		4,358		8,448
Income from equity method investments		36			89		98		346
Net gain ( loss) on disposal of assets and other income		(97)			12		(70)		(33)
Production expenses		406			593		1,300		1,697
Marketing costs		84			554		471		1,710
Exploration Expenses		585			96		786		314
Depreciation, depletion and amortization		717			737		2,289		2,060
Impairment of Oil and Gas Properties		337			109		381		130
Other expenses	[1]	218			259		745		789
Taxes other than income		46			115		191		319
Net interest and other		75			55		180		180
Income tax provision (benefit)		(396)			149		(546)		500
Segment income (loss) /Loss from continuing operations		(749)			304		(1,411)		1,062
Capital expenditures	[2]	595			1,508		2,375		3,833
Workforce reduction		4					47
Deferred Income Tax Expense (Benefit)							(590)		337
North America Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues		796			1,586		2,639		4,518
Marketing revenues		57			506		345		1,486
Total revenues		853			2,092		2,984		6,004
Income from equity method investments		0			0		0		0
Net gain ( loss) on disposal of assets and other income		6			(1)		17		17
Production expenses		179			233		560		661
Marketing costs		56			507		348		1,484
Exploration Expenses		22			55		148		194
Depreciation, depletion and amortization		549			609		1,866		1,674
Impairment of Oil and Gas Properties		0			0		0		21
Other expenses	[1]	106			118		322		354
Taxes other than income		42			109		170		301
Net interest and other		0			0		0		0
Income tax provision (benefit)		(34)			168		(146)		496
Segment income (loss) /Loss from continuing operations		(61)			292		(267)		836
Capital expenditures	[2]	564			1,277		2,048		3,246
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues		182			273		575		1,000
Marketing revenues		25			46		81		177
Total revenues		207			319		656		1,177
Income from equity method investments		48			89		110		346
Net gain ( loss) on disposal of assets and other income		6			12		20		44
Production expenses		61			108		192		307
Marketing costs		25			45		79		176
Exploration Expenses		10			41		85		120
Depreciation, depletion and amortization		79			55		214		201
Impairment of Oil and Gas Properties		0			0		0		0
Other expenses	[1]	25			26		67		98
Taxes other than income		0			0		0		0
Net interest and other		0			0		0		0
Income tax provision (benefit)		32			39		56		178
Segment income (loss) /Loss from continuing operations		29			106		93		487
Capital expenditures	[2]	30			166		275		386
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues		242			457		614		1,217
Marketing revenues		2			2		45		50
Total revenues		244			459		659		1,267
Income from equity method investments		0			0		0		0
Net gain ( loss) on disposal of assets and other income		0			0		1		3
Production expenses		166			252		548		729
Marketing costs		3			2		44		50
Exploration Expenses		0			0		0		0
Depreciation, depletion and amortization		76			62		173		152
Impairment of Oil and Gas Properties		4			0		4		0
Other expenses	[1]	8			14		26		40
Taxes other than income		5			5		15		16
Net interest and other		0			0		0		0
Income tax provision (benefit)		(7)			31		(43)		71
Segment income (loss) /Loss from continuing operations		(11)			93		(107)		212
Capital expenditures	[2]	(11)			49		26		172
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues		80	[3]		0		59	[3]	0
Marketing revenues		0			0		0		0
Total revenues		80			0		59		0
Income from equity method investments		(12)	[4]		0		(12)	[4]	0
Net gain ( loss) on disposal of assets and other income		(109)	[5]		1		(108)	[5]	(97)	[6]
Production expenses		0			0		0		0
Marketing costs		0			0		0		0
Exploration Expenses		553	[7]		0		553	[7]	0
Depreciation, depletion and amortization		13			11		36		33
Impairment of Oil and Gas Properties	[8]	333			109		377		109
Other expenses	[1]	79	[9]		101	[10]	330	[11]	297	[12]
Taxes other than income		(1)			1		6		2
Net interest and other		75			55		180		180
Income tax provision (benefit)		(387)			(89)		(413)	[13]	(245)
Segment income (loss) /Loss from continuing operations		(706)			(187)		(1,130)		(473)
Capital expenditures	[2]	12			16		26		29
United States and Foreign Pension Plans Defined Benefit [Member]
Segment Reporting Information [Line Items]
Net settlement loss	[14]	$ 18			$ 22		99		$ 93
Foreign Tax Authority [Member] | Alberta Government [Member]
Segment Reporting Information [Line Items]
Deferred Income Tax Expense (Benefit)				$ 135			$ 135

[1] Includes other operating expenses and general and administrative expenses.

[2] Includes accruals.

[3] Unrealized gain on crude oil derivative instruments.

[4] Partial impairment of investment in equity method investee (See Note 15).

[5] Includes loss on sale of East Africa exploration acreage (See Note 6).

[6] Primarily related to the sale of non-core acreage (See Note 6).

[7] Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

[8] Proved property impairments (See Note 14).

[9] Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).

[10] Includes pension settlement loss of $22 million (See Note 8)

[11] Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).

[12] Includes pension settlement loss of $93 million (See Note 8)

[13] Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (See Note 9).

[14] Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.

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Variable Interest Entity

9 Months Ended

Sep. 30, 2015

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Variable Interest Entity [Text Block]

Variable Interest Entity

The owners of the Athabasca Oil Sands Project, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at September 30, 2015 and $3 million at December 31, 2014.  This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE.  We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $471 million as of September 30, 2015.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.

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Derivatives Derivatives (Details 4-Non Hedges Commodity) (Details)	Sep. 30, 2015 BBL / Days $ / bbl
Three-Way Collars Oct-Dec15 [Member]
Derivative [Line Items]
Barrels per day (BBL per day) | BBL / Days	35,000
Price per barrel ceiling (usd per barrel)	70.34
Price per barrel floor (usd per barrel)	55.57
Price per barrel sold put (usd per barrel)	41.29
Three-Way Collars Oct15-Mar16 [Member]
Derivative [Line Items]
Barrels per day (BBL per day) | BBL / Days	2,000	[1]
Price per barrel ceiling (usd per barrel)	60.00	[1]
Price per barrel floor (usd per barrel)	50.00	[1]
Price per barrel sold put (usd per barrel)	40.00	[1]
Three-Way Collars Jan-Dec16 [Member] [Member]
Derivative [Line Items]
Barrels per day (BBL per day) | BBL / Days	12,000
Price per barrel ceiling (usd per barrel)	71.84
Price per barrel floor (usd per barrel)	60.48
Price per barrel sold put (usd per barrel)	50.00
Three-Way Collars Jan-Jun16 [Member] [Member] [Member]
Derivative [Line Items]
Barrels per day (BBL per day) | BBL / Days	2,000	[2]
Price per barrel ceiling (usd per barrel)	73.13	[2]
Price per barrel floor (usd per barrel)	65.00	[2]
Price per barrel sold put (usd per barrel)	50.00	[2]
Call Options Jan-Dec16 [Member]
Derivative [Line Items]
Barrels per day (BBL per day) | BBL / Days	10,000	[3]
Derivative, Price Risk Option Strike Price	72.39	[3]

[1] Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.

[2] Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.

[3] Call options settle monthly.

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Income per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations Attributable to Parent	$ (749)	$ 304	$ (1,411)	$ 1,062
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	0	127	0	1,058
Net income (loss)	$ (749)	$ 431	$ (1,411)	$ 2,120
Weighted average common shares outstanding, basic	677	675	677	681
Effect of dilutive securities	0	3	0	3
Weighted average common shares outstanding, diluted	677	678	677	684
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	13	2	13	4
Basic:
Income (loss) from continuing operations per basic share	$ (1.11)	$ 0.45	$ (2.09)	$ 1.56
Discontinued operations per basic share	0.00	0.19	0.00	1.55
Net income (loss), per basic share	(1.11)	0.64	(2.09)	3.11
Diluted:
Income (loss) from continuing operations per diluted share	(1.11)	0.45	(2.09)	1.55
Discontinued operations per diluted share	0.00	0.19	0.00	1.55
Net income (loss), per diluted share	$ (1.11)	$ 0.64	$ (2.09)	$ 3.10

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Income per Common Share (Tables)

9 Months Ended

Sep. 30, 2015

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

The per share calculations below exclude 13 million and 2 million stock options for the third quarters of 2015 and 2014 and 13 million and 4 million stock options for the first nine months of 2015 and 2014 that were antidilutive.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2015			2014		2015			2014
Income (loss) from continuing operations	$	(749	)	$	304	$	(1,411	)	$	1,062
Discontinued operations	—			127		—			1,058
Net income (loss)	$	(749	)	$	431	$	(1,411	)	$	2,120
Weighted average common shares outstanding	677			675		677			681
Effect of dilutive securities	—			3		—			3
Weighted average common shares, diluted	677			678		677			684
Per basic share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.10

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Basis of Presentation Accounting Policy (Policies)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.

As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2014 Annual Report on Form 10-K.  The results of operations for the third quarter and first nine months of2015 are not necessarily indicative of the results to be expected for the full year.

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Fair Value Measurements (Details-Recurring) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		$ 76	$ 8
Derivative Liability		3
Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	[1]	61
Derivative Liability	[1]	3
Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		15	8
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		0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	[1]	0
Derivative Liability	[1]	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		76	8
Derivative Liability		3
Fair Value Inputs Level 2 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	[1]	61
Derivative Liability	[1]	3
Fair Value Inputs Level 2 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		15	8
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
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	[1]	0
Derivative Liability	[1]	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

[1] Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).

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Acquisitions (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 0	$ 12
Oklahoma Resource Basins [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired	$ 68

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Dispositions (Tables)

9 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

Select amounts reported in discontinued operations were as follows:

	Three Months Ended September 30,			Nine Months Ended September 30,
(In millions)		2014			2014
Revenues applicable to discontinued operations		$	528		$	1,901
Pretax income from discontinued operations		$	487		$	1,617
After-tax income from discontinued operations		$	127		$	449	(a)

^(a)Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.

In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.

Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the prior period. Select amounts reported in discontinued operations were as follows:

	Nine Months Ended September 30,
(In millions)	2014
Revenues applicable to discontinued operations	$	58
Pretax income from discontinued operations, before gain	$	51
Pretax gain on disposition of discontinued operations	$	470
After-tax income from discontinued operations	$	609

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	796		$	182	$	242		$	80		(c)	$	1,300
Marketing revenues	57			25		2			—				84
Total revenues	853			207		244			80				1,384
Income (loss) from equity method investments	—			48		—			(12		)	(d)	36
Net gain (loss) on disposal of assets and other income	6			6		—			(109		)	(e)	(97		)
Less:
Production expenses	179			61		166			—				406
Marketing costs	56			25		3			—				84
Exploration expenses	22			10		—			553			(f)	585
Depreciation, depletion and amortization	549			79		76			13				717
Impairments	—			—		4			333			(g)	337
Other expenses (a)	106			25		8			79			(h)	218
Taxes other than income	42			—		5			(1		)		46
Net interest and other	—			—		—			75				75
Income tax provision (benefit)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Capital expenditures (b)	$	564		$	30	$	(11	)	$	12			$	595

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).

	Three Months Ended September 30, 2014
								Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,586		$	273	$	457	$	—			$	2,316
Marketing revenues	506			46		2		—				554
Total revenues	2,092			319		459		—				2,870
Income from equity method investments	—			89		—		—				89
Net gain (loss) on disposal of assets and other income	(1		)	12		—		1				12
Less:
Production expenses	233			108		252		—				593
Marketing costs	507			45		2		—				554
Exploration expenses	55			41		—		—				96
Depreciation, depletion and amortization	609			55		62		11				737
Impairments	—			—		—		109			(c)	109
Other expenses (a)	118			26		14		101			(d)	259
Taxes other than income	109			—		5		1				115
Net interest and other	—			—		—		55				55
Income tax provision (benefit)	168			39		31		(89		)		149
Segment income/Income from continuing operations	$	292		$	106	$	93	$	(187	)		$	304
Capital expenditures (b)	$	1,277		$	166	$	49	$	16			$	1,508

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Proved property impairment (See Note 14).

^(d)  Includes pension settlement loss of $22 million (See Note 8).

	Nine Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	2,639		$	575	$	614		$	59		(c)	$	3,887
Marketing revenues	345			81		45			—				471
Total revenues	2,984			656		659			59				4,358
Income (loss) from equity method investments	—			110		—			(12		)	(d)	98
Net gain (loss) on disposal of assets and other income	17			20		1			(108		)	(e)	(70		)
Less:
Production expenses	560			192		548			—				1,300
Marketing costs	348			79		44			—				471
Exploration expenses	148			85		—			553			(f)	786
Depreciation, depletion and amortization	1,866			214		173			36				2,289
Impairments	—			—		4			377			(g)	381
Other expenses (a)	322			67		26			330			(h)	745
Taxes other than income	170			—		15			6				191
Net interest and other	—			—		—			180				180
Income tax provision (benefit)	(146		)	56		(43		)	(413		)	(i)	(546		)
Segment income (loss) /Loss from continuing operations	$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Capital expenditures (b)	$	2,048		$	275	$	26		$	26			$	2,375

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity-method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).

⁽ⁱ⁾  Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (See Note 9).

	Nine Months Ended September 30, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	4,518	$	1,000	$	1,217	$	—			$	6,735
Marketing revenues	1,486		177		50		—				1,713
Total revenues	6,004		1,177		1,267		—				8,448
Income from equity method investments	—		346		—		—				346
Net gain (loss) on disposal of assets and other income	17		44		3		(97		)	(c)	(33		)
Less:
Production expenses	661		307		729		—				1,697
Marketing costs	1,484		176		50		—				1,710
Exploration expenses	194		120		—		—				314
Depreciation, depletion and amortization	1,674		201		152		33				2,060
Impairments	21		—		—		109			(d)	130
Other expenses (a)	354		98		40		297			(e)	789
Taxes other than income	301		—		16		2				319
Net interest and other	—		—		—		180				180
Income tax provision (benefit)	496		178		71		(245		)		500
Segment income /Income from continuing operations	$	836	$	487	$	212	$	(473	)		$	1,062
Capital expenditures (b)	$	3,246	$	386	$	172	$	29			$	3,833

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Primarily related to the sale of non-core acreage (See Note 6).

^(d)  Proved property impairments (See Note 14).

^(e)  Includes pension settlement loss of $93 million (See Note 8).

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Accounting Standards

9 Months Ended

Sep. 30, 2015

Accounting Standards Disclosure [Abstract]

Accounting Standards [Text Block]

Accounting Standards

Not Yet Adopted

In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner by which a reporting entity assesses whether the equity holders at risk lack decision making rights if the decision-making over the subject entity’s most significant activities was outsourced. This standard is effective for us in the first quarter of 2016 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards.  This standard is effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2014, 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 also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter of 2017. 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 April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required.  In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations.  The amendments were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact our consolidated results of operations, financial position or cash flows.

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Defined Benefit Postretirement Plans (Tables)

9 Months Ended

Sep. 30, 2015

Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following summarizes the components of net periodic benefit cost:

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	11		$	12		$	—		$	—
Interest cost	12			15			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	(3		)	1			(1		)	(1		)
– actuarial loss	5			7			1			—
Net settlement loss (a)	18			22			—			—
Net curtailment loss (b)	4			—			—			—
Net periodic benefit cost	$	30		$	41		$	3		$	3

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	35		$	35		$	2		$	2
Interest cost	39			46			8			10
Expected return on plan assets	(53		)	(48		)	—			—
Amortization:
– prior service cost (credit)	(4		)	4			(3		)	(3		)
– actuarial loss	19			23			1			—
Net settlement loss(a)	99			93			—			—
Net curtailment loss (gain) (b)	5			—			(4		)	—
Net periodic benefit cost	$	140		$	153		$	4		$	9

^(a)  Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.

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

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Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2015

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]

The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014			Income Statement Line
Postretirement and postemployment plans
Amortization of actuarial loss	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative
Net settlement loss	(18		)	(22		)	(99		)	(93		)	General and administrative
Net curtailment gain (loss)	(4		)	—			(1		)	—			General and administrative
	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations
	10			10			44			38			Benefit for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(18	)	$	(19	)	$	(76	)	$	(79	)	Income (loss) from continuing operations

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Other Noncurrent Assets (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Other Noncurrent Assets Disclosure [Abstract]
Deferred tax assets	$ 1,115	$ 525
Intangible assets	95	96
Other - Other Noncurrent Assets	217	185
Other noncurrent assets	$ 1,427	$ 806

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Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues and other income:
Sales and other operating revenues, including related party	$ 1,300	$ 2,316	$ 3,887	$ 6,735
Marketing revenues	84	554	471	1,713
Income from equity method investments	36	89	98	346
Net loss on disposal of assets	(109)	(3)	(108)	(88)
Other income	12	15	38	55
Total revenues and other income	1,323	2,971	4,386	8,761
Costs and expenses:
Production	406	593	1,300	1,697
Marketing, including purchases from related parties	84	554	471	1,710
Other operating	93	99	281	303
Exploration	585	96	786	314
Depreciation, depletion and amortization	717	737	2,289	2,060
Impairments	337	109	381	130
Taxes other than income	46	115	191	319
General and administrative	125	160	464	486
Total costs and expenses	2,393	2,463	6,163	7,019
Income (loss) from operations	(1,070)	508	(1,777)	1,742
Net interest and other	(75)	(55)	(180)	(180)
Income (loss) from continuing operations before income taxes	(1,145)	453	(1,957)	1,562
Provision (benefit) for income taxes	(396)	149	(546)	500
Income (loss) from continuing operations	(749)	304	(1,411)	1,062
Discontinued operations	0	127	0	1,058
Net income (loss)	$ (749)	$ 431	$ (1,411)	$ 2,120
Basic:
Income (loss) from continuing operations per basic share	$ (1.11)	$ 0.45	$ (2.09)	$ 1.56
Discontinued operations per basic share	0.00	0.19	0.00	1.55
Net income (loss), per basic share	(1.11)	0.64	(2.09)	3.11
Diluted:
Income (loss) from continuing operations per diluted share	(1.11)	0.45	(2.09)	1.55
Discontinued operations per diluted share	0.00	0.19	0.00	1.55
Net income (loss), per diluted share	(1.11)	0.64	(2.09)	3.10
Dividends paid, per share	$ 0.21	$ 0.21	$ 0.63	$ 0.59
Weighted average common shares outstanding, basic	677	675	677	681
Weighted average common shares outstanding, diluted	677	678	677	684

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Dispositions Dispositions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended			9 Months Ended
	Aug. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					$ 105	$ 2,237
East Texas/North Louisiana and Wilburton Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 100
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax		$ (1)			(1)
Kenya and Ethiopia Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax		(109)			(109)
Williston Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				$ 90
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax				$ (91)
Fair Value, Measurements, Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets, Fair Value Adjustment		337	$ 109		$ 381	$ 130
East Texas/North Louisiana and Wilburton Assets [Member] | Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets, Fair Value Adjustment		$ 44

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities:
Net income (loss)	$ (1,411)	$ 2,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	0	(1,058)
Deferred income taxes	(590)	337
Depreciation, depletion and amortization	2,289	2,060
Impairments	381	130
Pension and other postretirement benefits, net	9	(27)
Exploratory dry well costs and unproved property impairments	708	220
Net loss on disposal of assets	108	88
Equity method investments, net	41	51
Changes in:
Current receivables, changes in	738	(270)
Inventories, changes in	30	(32)
Current accounts payable and accrued liabilities, changes in	(954)	(115)
All other operating, net	(136)	(28)
Net cash provided by continuing operations	1,213	3,476
Net cash provided by discontinued operations	0	856
Net cash provided by operating activities	1,213	4,332
Investing activities:
Acquisitions, net of cash acquired	0	(12)
Additions to property, plant and equipment	(2,948)	(3,639)
Disposal of assets	105	2,237
Investments - return of capital	61	46
Purchases of short-term investments	(925)	0
Proceeds from Sale, Maturity and Collection of Investments	225	0
Investing activities of discontinued operations	0	(356)
All other investing, net	22	(24)
Net cash used in investing activities	(3,460)	(1,748)
Financing activities:
Commercial paper, net	0	(135)
Borrowings	1,996	0
Debt issuance costs	(19)	0
Debt repayments	(34)	(34)
Purchases of common stock	0	(1,000)
Dividends paid	(427)	(401)
All other financing, net	14	150
Net cash provided by (used in) financing activities	1,530	(1,420)
Effect of Exchange Rate on Cash and Cash Equivalents, Continuing Operations	(1)	(1)
Effect of Exchange Rate on Cash and Cash Equivalents, Discontinued Operations	0	(11)
Cash held for sale	0	(655)
Net increase (decrease) in cash and cash equivalents	(718)	497
Cash and cash equivalents at beginning of period	2,398	264
Cash and cash equivalents at end of period	$ 1,680	$ 761

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Derivatives (Details-BS) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 76
Derivative Asset, Fair Value, Gross Liability	3
Derivative Asset, Fair Value, Net	73
Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	61
Derivative Asset, Fair Value, Gross Liability	3
Derivative Asset, Fair Value, Net	58
Commodity Contract [Member] | Other Noncurrent Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6
Derivative Asset, Fair Value, Gross Liability	1
Derivative Asset, Fair Value, Net	5
Commodity Contract [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	55
Derivative Asset, Fair Value, Gross Liability	2
Derivative Asset, Fair Value, Net	53
Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15	$ 8
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	15	8
Fair Value Hedging [Member] | Interest rate [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15	8
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	$ 15	$ 8

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Other Noncurrent Assets (Tables)

9 Months Ended

Sep. 30, 2015

Other Noncurrent Assets Disclosure [Abstract]

Schedule of Other Assets, Noncurrent [Table Text Block]

	September 30,		December 31,
(in millions)	2015		2014
Deferred tax assets	$	1,115	$	525
Intangible assets	95		96
Other	217		185
Other noncurrent assets	$	1,427	$	806

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Incentive Based Compensation (Details 2-Restricted)	9 Months Ended
	Sep. 30, 2015 $ / shares shares
Restricted Stock
Beginning year unvested restricted stock	3,448,353
Granted restricted stock	2,674,987
Vested restricted stock	(1,135,635)
Forfeited restricted stock	(708,380)
End of period unvested restricted stock	4,279,325
Beginning year weighted average grant date fair value unvested restricted stock | $ / shares	$ 34.04
Granted restricted stock weighted average grant date fair value restricted stock | $ / shares	30.52
Vested restricted stock weighted average grant date fair value restricted stock | $ / shares	33.25
Forfeited restricted stock weighted average grant date fair value restricted stock | $ / shares	33.20
End of period weighted average grant date fair value unvested restricted stock | $ / shares	$ 32.17

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Derivatives

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives [Text Block]

Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 15. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets as of September 30, 2015 and December 31, 2014.

	September 30, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	15	$	—	$	15	Other noncurrent assets
Total Designated Hedges	15		—		15
Not Designated as Hedges
Commodity	55		2		53		Other current assets
Commodity	6		1		5		Other noncurrent assets
Total Not Designated as Hedges	61		3		58
Total	$	76	$	3	$	73

	December 31, 2014
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Total	$	8	$	—	$	8

Derivatives Designated as Fair Value Hedges

The following table presents, by maturity date, information about our interest rate swap agreements as of September 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

	September 30, 2015				December 31, 2014
	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	4.68	%	$	600	4.64	%
March 15, 2018	$	300	4.54	%	$	300	4.49	%

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.

		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other	$	4		$	(6	)	$	7		$	(3	)
Foreign currency	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	(4	)	$	6		$	(7	)	$	3
Accrued taxes	Discontinued operations	$	—		$	18		$	—		$	29

Derivatives not Designated as Hedges

During the first nine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives consist of three-way collars, extendable three-way collars and call options. Three way-collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract crude oil volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges and are shown in the table below:

Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29
Ceiling	$60.00	2,000	October 2015- March 2016 (a)
Floor	$50.00
Sold put	$40.00
Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00
Ceiling	$73.13	2,000	January- June 2016 (b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 (c)

^(a)  Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(b)  Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(c)  Call options settle monthly.

The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net gain of $108 million and $91 million in the third quarter and first nine months2015. There were no crude oil derivative instruments in the first nine months of 2014.

On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 18). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.

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Impairments and Exploration Expenses (Tables)

9 Months Ended

Sep. 30, 2015

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2015		2014		2015		2014
Total impairments	$	337	$	109	$	381	$	130

Exploration Expenses [Table Text Block]

The following table summarizes the components of exploration expenses:

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Exploration Expenses
Unproved property impairments	$	563		$	39	$	612	$	140
Dry well costs	(3		)	25		96		80
Geological and geophysical	8			10		23		27
Other	17			22		55		67
Total exploration expenses	$	585		$	96	$	786	$	314

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Debt (Notes)

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt

Debt

Revolving Credit Facility As of September 30, 2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described below.

In May 2015, we amended our $2.5 billion unsecured Credit Facility to increase the facility size by $500 million to a total of $3 billion and extended the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.

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 September 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 30%.

Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:

•$600 million of 2.70% senior notes due June 1, 2020

•$900 million of 3.85% senior notes due June 1, 2025

•$500 million of 5.20% senior notes due June 1, 2045

Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes. As of September 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.

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Debt (Details) - USD ($)	Sep. 30, 2015	Jun. 10, 2015
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent		$ 2,000,000,000
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.70%
Other Long-term Debt, Noncurrent		$ 600,000,000
Senior Unsecured Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.85%
Other Long-term Debt, Noncurrent		$ 900,000,000
Senior Unsecured Notes Due 2045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.20%
Other Long-term Debt, Noncurrent		$ 500,000,000
Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.90%
Other Long-term Debt, Noncurrent	$ 1,000,000,000

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Basis of Presentation

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Basis of Presentation [Text Block]

Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.

As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2014 Annual Report on Form 10-K.  The results of operations for the third quarter and first nine months of2015 are not necessarily indicative of the results to be expected for the full year.

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (749)	$ 431	$ (1,411)	$ 2,120
Postretirement and postemployment plans
Change in actuarial loss and other	(2)	3	160	(40)
Income tax benefit (provision) on postretirement and postemployment plans	(1)	(2)	(58)	13
Postretirement and postemployment plans, net of tax	(3)	1	102	(27)
Comprehensive income (loss)	$ (752)	$ 432	$ (1,309)	$ 2,093

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Inventories

9 Months Ended

Sep. 30, 2015

Inventory Disclosure [Abstract]

Inventories [Text Block]

Inventories

 Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.

	September 30,		December 31,
(In millions)	2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	39	$	58
Supplies and other items	285		299
Inventories, at cost	$	324	$	357

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 31, 2015
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2015
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		677,260,116

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

 Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization

	September 30,		December 31,
(In millions)	2015		2014
North America E&P	$	15,875	$	16,717
International E&P	2,604		2,741
Oil Sands Mining	9,334		9,455
Corporate	107		127
Net property, plant and equipment	$	27,920	$	29,040

Our Libya operations continue to be impacted by civil unrest and, in December 2014, Libya’s National Oil Corporation once again declared force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.

As of September 30, 2015, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million boe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $775 million by a material amount.

Exploratory well costs capitalized greater than one year after completion of drilling were $88 million and $126 million as of September 30, 2015 and December 31, 2014. This $38 million net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage demonstration project at Birchwood.

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Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,680	$ 2,398
Short-term Investments	700	0
Receivables, less reserve of $4 and $3	991	1,729
Inventories	324	357
Other current assets	163	109
Total current assets	3,858	4,593
Equity method investments	1,012	1,113
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $23,713 and $21,884	27,920	29,040
Goodwill	457	459
Other noncurrent assets	1,427	806
Total assets	34,674	36,011
Current liabilities:
Accounts payable	1,246	2,545
Payroll and benefits payable	138	191
Accrued taxes	143	285
Other current liabilities	286	290
Long-term debt due within one year	1,035	1,068
Total current liabilities	2,848	4,379
Long-term debt	7,323	5,323
Deferred tax liabilities	2,542	2,486
Defined benefit postretirement plan obligations	436	598
Asset retirement obligations	1,965	1,917
Deferred credit and other liabilities	225	288
Total liabilities	$ 15,339	$ 14,991
Commitments and contingencies
Stockholders' Equity
Preferred stock - no shares issued or outstanding (no par value, 26 million shares authorized)	$ 0	$ 0
Common stock issued - 770 million shares (par value $1 per share, 1.1 billion shares authorized)	770	770
Common stock, securities exchangeable into common stock - no shares issued or outstanding (no par value, 29 million shares authorized)	0	0
Common stock, held in treasury, at cost - 93 million and 95 million shares	(3,553)	(3,642)
Additional paid-in capital	6,493	6,531
Retained earnings	15,800	17,638
Accumulated other comprehensive loss	(175)	(277)
Total stockholders' equity	19,335	21,020
Total liabilities and stockholders' equity	$ 34,674	$ 36,011

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Dispositions

9 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Dispositions [Text Block]

Dispositions

2015 - North America E&P Segment

In August 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (See Note 15).

2015 - International E&P Segment

In September 2015, we entered into an agreement 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 is expected to close during the fourth quarter of 2015.

2014 - North America E&P Segment

In the second quarter of 2014, we closed the sale of non-core acreage located in the far northwest portion of Williston Basin for proceeds of $90 million and recorded a pretax loss of $91 million.

2014 - International E&P Segment

In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea.  The transaction closed during the fourth quarter of 2014.

Our Norway business was reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2014. Select amounts reported in discontinued operations were as follows:

	Three Months Ended September 30,			Nine Months Ended September 30,
(In millions)		2014			2014
Revenues applicable to discontinued operations		$	528		$	1,901
Pretax income from discontinued operations		$	487		$	1,617
After-tax income from discontinued operations		$	127		$	449	(a)

^(a)Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.

In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.

Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the prior period. Select amounts reported in discontinued operations were as follows:

	Nine Months Ended September 30,
(In millions)	2014
Revenues applicable to discontinued operations	$	58
Pretax income from discontinued operations, before gain	$	51
Pretax gain on disposition of discontinued operations	$	470
After-tax income from discontinued operations	$	609

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Acquisitions (Notes)

9 Months Ended

Sep. 30, 2015

Acquisitions [Abstract]

Business Combination Disclosure [Text Block]

Acquisitions

2014 - North America E&P Segment

In the third quarter of 2014, we acquired acreage in the Oklahoma Resource Basins at a cost of $68 million after final settlement adjustments.

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Incentive Based Compensation

9 Months Ended

Sep. 30, 2015

Incentive Based Compensation Plans [Abstract]

Incentive Based Compensation [Text Block]

Incentive Based Compensation

Stock option and restricted stock awards

  The following table presents a summary of stock option and restricted stock award activity for the first nine months of 2015: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014	13,427,836				$29.68	3,448,353			$34.04
Granted	724,082		(a)		$29.06	2,674,987			$30.52
Options Exercised/Stock Vested	(549,926	)			$16.84	(1,135,635	)		$33.25
Canceled	(605,760	)			$34.11	(708,380	)		$33.20
Outstanding at September 30, 2015	12,996,232				$29.99	4,279,325			$32.17

^(a)    The weighted average grant date fair value of stock option awards granted was $6.84 per share.

Stock-based performance unit awards

 During the first nine months of 2015, we granted 382,335 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.

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Other Noncurrent Assets (Notes)

9 Months Ended

Sep. 30, 2015

Other Noncurrent Assets Disclosure [Abstract]

Other Assets Disclosure [Text Block]

Other Noncurrent Assets

	September 30,		December 31,
(in millions)	2015		2014
Deferred tax assets	$	1,115	$	525
Intangible assets	95		96
Other	217		185
Other noncurrent assets	$	1,427	$	806

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Income Taxes

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Effective Tax Rate

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 (benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.

Our effective income tax rates on continuing operations for the first nine months of 2015 and 2014 were 28% and 32%.  The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first nine months of 2015 and 2014.  Excluding Libya, the effective tax rates on continuing operations, would be 27% and 32% for the first nine months of 2015 and 2014. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability.  Thus, for the first nine months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).

Change in Tax Law

On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.

Indefinite Reinvestment Assertion

In the second quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of approximately $1 billion associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes were recorded in the second quarter of 2015.

Deferred Tax Assets

In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

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Derivatives (Details 2-Fair Value Hedges) - Fair Value Hedging [Member] - Designated as Hedging Instrument [Member] - Interest Rate Contract [Member] - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Notes Due 2018 [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 300	$ 300
Weighted-average, LIBOR-based, floating rate	4.54%	4.49%
Debentures Due 2017 [Member]
Derivative [Line Items]
Derivative, Notional Amount	$ 600	$ 600
Weighted-average, LIBOR-based, floating rate	4.68%	4.64%

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Segment Information

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Segment Information [Text Block]

Segment Information

  We are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• N.A. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;

• Int'l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

• Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

As discussed in Note 6, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the Int'l E&P segment for 2014.

	Three Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	796		$	182	$	242		$	80		(c)	$	1,300
Marketing revenues	57			25		2			—				84
Total revenues	853			207		244			80				1,384
Income (loss) from equity method investments	—			48		—			(12		)	(d)	36
Net gain (loss) on disposal of assets and other income	6			6		—			(109		)	(e)	(97		)
Less:
Production expenses	179			61		166			—				406
Marketing costs	56			25		3			—				84
Exploration expenses	22			10		—			553			(f)	585
Depreciation, depletion and amortization	549			79		76			13				717
Impairments	—			—		4			333			(g)	337
Other expenses (a)	106			25		8			79			(h)	218
Taxes other than income	42			—		5			(1		)		46
Net interest and other	—			—		—			75				75
Income tax provision (benefit)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Capital expenditures (b)	$	564		$	30	$	(11	)	$	12			$	595

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).

	Three Months Ended September 30, 2014
								Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,586		$	273	$	457	$	—			$	2,316
Marketing revenues	506			46		2		—				554
Total revenues	2,092			319		459		—				2,870
Income from equity method investments	—			89		—		—				89
Net gain (loss) on disposal of assets and other income	(1		)	12		—		1				12
Less:
Production expenses	233			108		252		—				593
Marketing costs	507			45		2		—				554
Exploration expenses	55			41		—		—				96
Depreciation, depletion and amortization	609			55		62		11				737
Impairments	—			—		—		109			(c)	109
Other expenses (a)	118			26		14		101			(d)	259
Taxes other than income	109			—		5		1				115
Net interest and other	—			—		—		55				55
Income tax provision (benefit)	168			39		31		(89		)		149
Segment income/Income from continuing operations	$	292		$	106	$	93	$	(187	)		$	304
Capital expenditures (b)	$	1,277		$	166	$	49	$	16			$	1,508

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Proved property impairment (See Note 14).

^(d)  Includes pension settlement loss of $22 million (See Note 8).

	Nine Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	2,639		$	575	$	614		$	59		(c)	$	3,887
Marketing revenues	345			81		45			—				471
Total revenues	2,984			656		659			59				4,358
Income (loss) from equity method investments	—			110		—			(12		)	(d)	98
Net gain (loss) on disposal of assets and other income	17			20		1			(108		)	(e)	(70		)
Less:
Production expenses	560			192		548			—				1,300
Marketing costs	348			79		44			—				471
Exploration expenses	148			85		—			553			(f)	786
Depreciation, depletion and amortization	1,866			214		173			36				2,289
Impairments	—			—		4			377			(g)	381
Other expenses (a)	322			67		26			330			(h)	745
Taxes other than income	170			—		15			6				191
Net interest and other	—			—		—			180				180
Income tax provision (benefit)	(146		)	56		(43		)	(413		)	(i)	(546		)
Segment income (loss) /Loss from continuing operations	$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Capital expenditures (b)	$	2,048		$	275	$	26		$	26			$	2,375

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain on crude oil derivative instruments.

^(d)  Partial impairment of investment in equity-method investee (See Note 15).

^(e)  Includes loss on sale of East Africa exploration acreage (See Note 6).

^(f)  Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).

^(g)  Proved property impairments (See Note 14).

^(h)  Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).

⁽ⁱ⁾  Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (See Note 9).

	Nine Months Ended September 30, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	4,518	$	1,000	$	1,217	$	—			$	6,735
Marketing revenues	1,486		177		50		—				1,713
Total revenues	6,004		1,177		1,267		—				8,448
Income from equity method investments	—		346		—		—				346
Net gain (loss) on disposal of assets and other income	17		44		3		(97		)	(c)	(33		)
Less:
Production expenses	661		307		729		—				1,697
Marketing costs	1,484		176		50		—				1,710
Exploration expenses	194		120		—		—				314
Depreciation, depletion and amortization	1,674		201		152		33				2,060
Impairments	21		—		—		109			(d)	130
Other expenses (a)	354		98		40		297			(e)	789
Taxes other than income	301		—		16		2				319
Net interest and other	—		—		—		180				180
Income tax provision (benefit)	496		178		71		(245		)		500
Segment income /Income from continuing operations	$	836	$	487	$	212	$	(473	)		$	1,062
Capital expenditures (b)	$	3,246	$	386	$	172	$	29			$	3,833

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Primarily related to the sale of non-core acreage (See Note 6).

^(d)  Proved property impairments (See Note 14).

^(e)  Includes pension settlement loss of $93 million (See Note 8).

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Defined Benefit Postretirement Plans

9 Months Ended

Sep. 30, 2015

Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans [Text Block]

Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	11		$	12		$	—		$	—
Interest cost	12			15			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	(3		)	1			(1		)	(1		)
– actuarial loss	5			7			1			—
Net settlement loss (a)	18			22			—			—
Net curtailment loss (b)	4			—			—			—
Net periodic benefit cost	$	30		$	41		$	3		$	3

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	35		$	35		$	2		$	2
Interest cost	39			46			8			10
Expected return on plan assets	(53		)	(48		)	—			—
Amortization:
– prior service cost (credit)	(4		)	4			(3		)	(3		)
– actuarial loss	19			23			1			—
Net settlement loss(a)	99			93			—			—
Net curtailment loss (gain) (b)	5			—			(4		)	—
Net periodic benefit cost	$	140		$	153		$	4		$	9

^(a)  Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.

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

During the first nine months of 2015, we recorded the effects of a workforce reduction, a U.S. pension plan amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula and was effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first nine months of 2015 and 2014, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.

During the first nine months of 2015, we made contributions of $65 million to our funded pension plans.  We expect to make additional contributions up to an estimated $18 million to our funded pension plans over the remainder of 2015.  During the first nine months of 2015, we made payments of $57 million and $13 million related to unfunded pension plans and other postretirement benefit plans, respectively.

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Short-term Investments (Notes)

9 Months Ended

Sep. 30, 2015

Short-term Investments [Abstract]

Investment [Text Block]

Short-term Investments

As of September 30, 2015, our short-term investments are comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. They are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values of our short-term investments approximate fair value. These short-term investments matured during October 2015.

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Incentive Based Compensation (Details)	9 Months Ended
	Sep. 30, 2015 $ / shares shares
Stock Options
Beginning year stock option awards | shares	13,427,836
Granted stock option awards | shares	724,082	[1]
Exercised stock option awards | shares	(549,926)
Canceled stock option awards | shares	(605,760)
End of period stock option awards | shares	12,996,232
Beginning year weighted average exercise price	$ 29.68
Granted weighted average exercise price	29.06
Exercises weighted average exercise price	16.84
Canceled weighted average exercise price	34.11
End of period weighted average exercise price	29.99
Stock options weighted average grant date fair value	$ 6.84

[1] The weighted average grant date fair value of stock option awards granted was $6.84 per share.

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Incentive Based Compensation (Details 3-Performance) - $ / shares	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 32.17	$ 34.04
Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Instruments Other Than Options Performance Unit Granted	382,335
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 31.77

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Derivatives Derivatives (Details 5-Non Hedges) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2015
Commodity [Member] | Sales and other operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 108		$ 91
Treasury Lock [Member] | Net interest and other [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 6

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2015

Property, Plant and Equipment [Abstract]

Schedule Of Property Plant And Equipment [Table Text Block]

	September 30,		December 31,
(In millions)	2015		2014
North America E&P	$	15,875	$	16,717
International E&P	2,604		2,741
Oil Sands Mining	9,334		9,455
Corporate	107		127
Net property, plant and equipment	$	27,920	$	29,040

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Property, Plant and Equipment (Details) Boe in Millions, $ in Millions	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($) Boe
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 27,920	$ 29,040
LIBYAN ARAB JAMAHIRIYA
Segment Reporting Information [Line Items]
Property, plant and equipment, net	775
Proved Developed and Undeveloped Reserves, Net (BOE) | Boe		243
North America Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	15,875	$ 16,717
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	2,604	2,741
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	9,334	9,455
Corporate [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 107	$ 127

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Fair Value Measurements

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 by fair value hierarchy level.

	September 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity (a)	$	—	$	61	$	—	$	61
Interest rate	—		15		—		15
Derivative instruments, assets	$	—	$	76	$	—	$	76
Derivative instruments, liabilities
Commodity (a)	$	—	$	3	$	—	$	3
Derivative instruments, liabilities	$	—	$	3	$	—	$	3

^(a) Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8
Derivative instruments, assets	$	—	$	8	$	—	$	8

Commodity derivatives include three-way collars, swaptions, extendable three-way collars and call options. These instruments are measured at fair value using either the Black-Scholes Model or Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 16 for additional discussion of the types of derivative instruments we use.

Fair Values - Nonrecurring

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

	Three Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	41	$	337	$	43	$	109

	Nine Months Ended September 30,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	58	$	381	$	43	$	130

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. The prolonged decline in commodity prices, and the resulting change in management's future commodity price assumptions, was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future. Long-lived assets held for use that were impaired are discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs, unless otherwise noted.  Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

2015 - North America E&P

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

    During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale (see Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model.

2015 - International E&P

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

2014 - North America E&P

The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first nine months of 2014, we recorded additional impairments of $30 million as a result of estimated abandonment cost revisions.

In the third quarter of 2014, impairments of $53 million were recorded to certain other Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two additional on-shore fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.

Fair Values – Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	109	$	116	$	132	$	129
Total financial assets	109		116		132		129
Financial liabilities
Other current liabilities	15		14		13		13
Long-term debt, including current portion (a)	8,302		8,324		6,887		6,360
Deferred credits and other liabilities	69		64		69		68
Total financial liabilities	$	8,386	$	8,402	$	6,969	$	6,441

^(a)    Excludes capital leases.

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

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

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Text Block]

Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2015			2014
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(200	)	$	(201	)
Income taxes paid to taxing authorities (a)	(174		)	(1,514		)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances	$	—		$	2,285
Repayments	—			(2,420		)
Commercial paper, net	$	—		$	(135	)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized, net of revisions	$	12		$	240
Asset retirement obligations assumed by buyer	23			52
Receivable for disposal of assets	—			44

^(a)  The first nine months of 2014 included $1,195 million related to discontinued operations.

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Income Taxes (Details) - USD ($) $ in Millions			3 Months Ended	9 Months Ended
	Jun. 29, 2015	Jun. 28, 2015	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Effective Tax Rate Reconciliation [Abstract]
Effective income tax rate				28.00%	32.00%
Effective income tax rate excluding Libya				27.00%	32.00%
Deferred Income Tax Expense (Benefit)				$ (590)	$ 337
Foreign Tax Authority [Member] | Alberta Government [Member]
Effective Tax Rate Reconciliation [Abstract]
Provincial corporate tax rate	12.00%	10.00%
Deferred Income Tax Expense (Benefit)			$ 135	$ 135
CANADA
Effective Tax Rate Reconciliation [Abstract]
Earnings of foreign subsidiaries no longer permanently reinvested			$ 1,000

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Table Text Block]

Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2015			2014
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	(200	)	$	(201	)
Income taxes paid to taxing authorities (a)	(174		)	(1,514		)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances	$	—		$	2,285
Repayments	—			(2,420		)
Commercial paper, net	$	—		$	(135	)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized, net of revisions	$	12		$	240
Asset retirement obligations assumed by buyer	23			52
Receivable for disposal of assets	—			44

^(a)  The first nine months of 2014 included $1,195 million related to discontinued operations.

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Consolidated Balance Sheets Parentheticals - USD ($) shares in Millions, $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Consolidated Balance Sheets Parenthetical [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 4	$ 3
Less accumulated depreciation, depletion and amortization	$ (23,713)	$ (21,884)
Preferred stock, no par value	$ 0	$ 0
Preferred stock shares authorized	26	26
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	1,100
Common stock, shares issued	770	770
Common stock, securities exchangeable, no par value	$ 0	$ 0
Common stock, securities exchangeable, shares authorized	29	29
Common stock, securities exchangeable, shares issued	0	0
Common stock, securities exchangeable, shares outstanding	0	0
Common stock, held in treasury, shares	93	95

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Income per Common Share

9 Months Ended

Sep. 30, 2015

Earnings Per Share [Abstract]

Income per Common Share [Text Block]

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, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 2 million stock options for the third quarters of 2015 and 2014 and 13 million and 4 million stock options for the first nine months of 2015 and 2014 that were antidilutive.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2015			2014		2015			2014
Income (loss) from continuing operations	$	(749	)	$	304	$	(1,411	)	$	1,062
Discontinued operations	—			127		—			1,058
Net income (loss)	$	(749	)	$	431	$	(1,411	)	$	2,120
Weighted average common shares outstanding	677			675		677			681
Effect of dilutive securities	—			3		—			3
Weighted average common shares, diluted	677			678		677			684
Per basic share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45	$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64	$	(2.09	)	$	3.10

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Fair Value Measurements (Details 3-Reported) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Fair Value [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets		$ 109	$ 132
Total financial assets		109	132
Financial liabilities
Other current financial liabilities		15	13
Long-term debt, including current portion	[1]	8,302	6,887
Deferred credits and other financial liabilities		69	69
Financial Liabilities Fair Value Disclosure		8,386	6,969
Carrying Amount [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets		116	129
Total financial assets		116	129
Financial liabilities
Other current financial liabilities		14	13
Long-term debt, including current portion	[1]	8,324	6,360
Deferred credits and other financial liabilities		64	68
Financial Liabilities Fair Value Disclosure		$ 8,402	$ 6,441

[1] Excludes capital leases.

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Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Provision for income taxes	$ 396	$ (149)	$ 546	$ (500)
Other insignificant, net of tax	(93)	(99)	(281)	(303)
Total reclassifications	(749)	431	(1,411)	2,120
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of actuarial loss	(6)	(7)	(20)	(23)
Net settlement loss	(18)	(22)	(99)	(93)
Net curtailment gain (loss)	(4)	0	(1)	0
Income before income taxes	(28)	(29)	(120)	(116)
Provision for income taxes	10	10	44	38
Other insignificant, net of tax	0	0	0	(1)
Total reclassifications	$ (18)	$ (19)	$ (76)	$ (79)

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

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

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives as they appear on the balance sheet [Table Text Block]

The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets as of September 30, 2015 and December 31, 2014.

	September 30, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	15	$	—	$	15	Other noncurrent assets
Total Designated Hedges	15		—		15
Not Designated as Hedges
Commodity	55		2		53		Other current assets
Commodity	6		1		5		Other noncurrent assets
Total Not Designated as Hedges	61		3		58
Total	$	76	$	3	$	73

	December 31, 2014
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Total	$	8	$	—	$	8

Schedule of Interest Rate Derivatives [Table Text Block]

The following table presents, by maturity date, information about our interest rate swap agreements as of September 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

	September 30, 2015				December 31, 2014
	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	4.68	%	$	600	4.64	%
March 15, 2018	$	300	4.54	%	$	300	4.49	%

Effects of derivatives designated as fair value hedges [Table Text Block]

		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other	$	4		$	(6	)	$	7		$	(3	)
Foreign currency	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	(4	)	$	6		$	(7	)	$	3
Accrued taxes	Discontinued operations	$	—		$	18		$	—		$	29

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

These commodity derivatives were not designated as hedges and are shown in the table below:

Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29
Ceiling	$60.00	2,000	October 2015- March 2016 (a)
Floor	$50.00
Sold put	$40.00
Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00
Ceiling	$73.13	2,000	January- June 2016 (b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 (c)

^(a)  Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(b)  Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.

^(c)  Call options settle monthly.

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Impairments and Exploration Expenses (Notes)

9 Months Ended

Sep. 30, 2015

Impairments and Exploration Expenses [Abstract]

Impairments and Exploration Expenses [Text Block]

Impairments and Exploration Expenses

The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.

The following table summarizes impairment charges of proved properties:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2015		2014		2015		2014
Total impairments	$	337	$	109	$	381	$	130

Impairments for the three and nine months ended September 30, 2015 consisted primarily of proved properties in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices.

Impairments for the three and nine months ended September 30, 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Note 7 for relevant detail regarding segment presentation and Note 15 for fair value measurements related to impairments of proved properties.

The following table summarizes the components of exploration expenses:

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Exploration Expenses
Unproved property impairments	$	563		$	39	$	612	$	140
Dry well costs	(3		)	25		96		80
Geological and geophysical	8			10		23		27
Other	17			22		55		67
Total exploration expenses	$	585		$	96	$	786	$	314

Included in the unproved property impairments for the three and nine months ended September 30, 2015 are non-cash charges of $553 million as a result of changes in our conventional exploration strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).

Unproved property impairments for the three and nine months ended September 30, 2014 primarily consist of leases in Texas and North Dakota that either expired or we decided not to drill or extend. See Note 7 for relevant detail regarding segment presentation.