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 June 30, ~~2013~~2014



[ ]	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 ~~709,671,894~~674,484,400 shares of Marathon Oil Corporation common stock outstanding as of July 31, ~~2013~~2014.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, ~~2013~~2014

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions, except per share data)	2013			2012			2013			2012			2014			2013			2014			2013
Revenues and other income:
Sales and other operating revenues, including related party	$	3,419		$	2,975		$	6,859		$	5,919		$	2,270		$	2,513		$	4,419		$	4,961
Marketing revenues	499			757			929			1,606			618			497			1,159			929
Income from equity method investments	77			60			195			138			120			77			257			195
Net gain (loss) on disposal of assets	(107		)	(28		)	2			138			(87		)	(107		)	(85		)	2
Other income	10			20			19			23			20			10			40			19
Total revenues and other income	3,898			3,784			8,004			7,824			2,941			2,990			5,790			6,106
Costs and expenses:
Production	614			485			1,192			987			562			552			1,104			1,085
Marketing, including purchases from related parties	495			755			924			1,609			614			494			1,156			927
Other operating	86			107			197			199			101			70			204			168
Exploration	133			172			598			307			145			125			218			582
Depreciation, depletion and amortization	738			580			1,485			1,154			680			626			1,323			1,257
Impairments	—			1			38			263			4			—			21			38
Taxes other than income	93			55			177			123			109			93			204			175
General and administrative	164			154			338			313			139			159			326			322
Total costs and expenses	2,323			2,309			4,949			4,955			2,354			2,119			4,556			4,554
Income from operations	1,575			1,475			3,055			2,869			587			871			1,234			1,552
Net interest and other	(71		)	(57		)	(143		)	(107		)	(76		)	(67		)	(125		)	(140		)
Income before income taxes	1,504			1,418			2,912			2,762
Income from continuing operations before income taxes													511			804			1,109			1,412
Provision for income taxes	1,078			1,025			2,103			1,952			151			563			351			1,013
Income from continuing operations													360			241			758			399
Discontinued operations													180			185			931			410
Net income	$	426		$	393		$	809		$	810		$	540		$	426		$	1,689		$	809
Per Share Data
Net Income:
Basic:
Income from continuing operations													$0.53			$0.34			$1.11			$0.56
Discontinued operations													$0.27			$0.26			$1.36			$0.58
Net income													$0.80			$0.60			$2.47			$1.14
Diluted:
Income from continuing operations													$0.53			$0.34			$1.10			$0.56
Discontinued operations													$0.27			$0.26			$1.36			$0.58
Net income													$0.80			$0.60			$2.46			$1.14
Dividends													$0.19			$0.17			$0.38			$0.34
Weighted average common shares:
Basic	$	0.60		$	0.56		$	1.14		$	1.15		676			710			684			709
Diluted	$	0.60		$	0.56		$	1.14		$	1.14		679			714			688			713
Dividends paid	$	0.17		$	0.17		$	0.34		$	0.34
Weighted average shares:
Basic	710			706			709			705
Diluted	714			709			713			709

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions)	2013			2012			2013			2012			2014			2013			2014			2013
Net income	$	426		$	393		$	809		$	810		$	540		$	426		$	1,689		$	809
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	133			(3		)	146			10			(13		)	133			(43		)	146
Income tax (provision) benefit on postretirement and
postemployment plans	(49		)	1			(54		)	(4		)
Income tax benefit (provision)													5			(49		)	15			(54		)
Postretirement and postemployment plans, net of tax	84			(2		)	92			6			(8		)	84			(28		)	92
Foreign currency translation and other
Unrealized loss	(3		)	(1		)	(4		)	—
Income tax benefit on foreign currency translation and other	1			—			1			—
Unrealized gain (loss)													1			(3		)	1			(4		)
Income tax benefit (provision)													(1		)	1			(1		)	1
Foreign currency translation and other, net of tax	(2		)	(1		)	(3		)	—			—			(2		)	—			(3		)
Other comprehensive income (loss)	82			(3		)	89			6			(8		)	82			(28		)	89
Comprehensive income	$	508		$	390		$	898		$	816		$	532		$	508		$	1,661		$	898

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			June 30,			December 31,
(In millions, except per share data)	2013			2012			2014			2013
Assets
Current assets:
Cash and cash equivalents	$	246		$	684		$	1,169		$	264
Receivables	2,443			2,418			2,042			2,134
Inventories	368			361			404			364
Other current assets	224			299			211			172
Current assets held for sale							392			41
Total current assets	3,281			3,762			4,218			2,975
Equity method investments	1,244			1,279			1,184			1,201
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $20,639 and $19,266	27,457			28,272
depletion and amortization of $20,207 and $21,895							27,824			28,145
Goodwill	499			525			457			499
Other noncurrent assets	2,567			1,468			1,088			1,153
Noncurrent assets held for sale							1,164			1,647
Total assets	$	35,048		$	35,306		$	35,935		$	35,620
Liabilities
Current liabilities:
Commercial paper	$	—		$	200		$	—		$	135
Accounts payable	2,152			2,324			2,439			2,206
Payroll and benefits payable	137			217			121			240
Accrued taxes	1,397			1,983			193			1,445
Other current liabilities	254			173			147			214
Long-term debt due within one year	68			184			68			68
Current liabilities held for sale							1,006			25
Total current liabilities	4,008			5,081			3,974			4,333
Long-term debt	6,428			6,512			6,362			6,394
Deferred tax liabilities	2,406			2,432			2,525			2,492
Defined benefit postretirement plan obligations	739			856			668			604
Asset retirement obligations	2,039			1,749			1,804			2,009
Deferred credits and other liabilities	407			393			392			401
Noncurrent liabilities held for sale							342			43
Total liabilities	16,027			17,023			16,067			16,276
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—			—			—
Common stock:
Issued – 770 million and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770			770			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—			—			—
Held in treasury, at cost – 61 million and 63 million shares	(2,477		)	(2,560		)
Held in treasury, at cost – 97 million and 73 million shares							(3,718		)	(2,903		)
Additional paid-in capital	6,614			6,616			6,530			6,592
Retained earnings	14,458			13,890			16,564			15,135
Accumulated other comprehensive loss	(344		)	(433		)	(278		)	(250		)
Total equity	19,021			18,283
Total stockholders' equity							19,868			19,344
Total liabilities and stockholders' equity	$	35,048		$	35,306		$	35,935		$	35,620

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2014			2013
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	809		$	810		$	1,689		$	809
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations							(931		)	(410		)
Deferred income taxes	113			75			173			35
Depreciation, depletion and amortization	1,485			1,154			1,323			1,257
Impairments	38			263			21			38
Pension and other postretirement benefits, net	34			(22		)	26			33
Exploratory dry well costs and unproved property impairments	494			174			156			494
Net gain on disposal of assets	(2		)	(138		)
Net (gain) loss on disposal of assets							85			(2		)
Equity method investments, net	—			7			(10		)	—
Changes in:
Current receivables	17			(107		)	(266		)	(11		)
Inventories	(16		)	(18		)	(58		)	(19		)
Current accounts payable and accrued liabilities	(651		)	(450		)	(31		)	(284		)
All other operating, net	75			(6		)	(59		)	(18		)
Net cash provided by continuing operations							2,118			1,922
Net cash provided by discontinued operations							440			474
Net cash provided by operating activities	2,396			1,742			2,558			2,396
Investing activities:
Additions to property, plant and equipment	(2,676		)	(2,181		)	(2,230		)	(2,405		)
Disposal of assets	333			218			2,232			333
Investments - return of capital	29			21			27			29
Investing activities of discontinued operations							(233		)	(271		)
All other investing, net	15			(59		)	—			15
Net cash used in investing activities	(2,299		)	(2,001		)	(204		)	(2,299		)
Financing activities:
Commercial paper, net	(200		)	550			(135		)	(200		)
Debt issuance costs	—			(9		)
Debt repayments	(148		)	(111		)	(34		)	(148		)
Purchases of common stock							(1,000		)	—
Dividends paid	(241		)	(240		)	(260		)	(241		)
All other financing, net	46			20			86			46
Net cash (used in) provided by financing activities	(543		)	210
Effect of exchange rate changes on cash	8			8
Net decrease in cash and cash equivalents	(438		)	(41		)
Net cash used in financing activities							(1,343		)	(543		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations							—			4
Discontinued operations							(10		)	4
Cash held for sale							(96		)	—
Net increase (decrease) in cash and cash equivalents							905			(438		)
Cash and cash equivalents at beginning of period	684			493			264			684
Cash and cash equivalents at end of period	$	246		$	452		$	1,169		$	246

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

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 Securities and Exchange Commission ("SEC") and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements.

~~Beginning~~As the result of the sale of our Angola assets in the first quarter of ~~2013, we changed~~2014 and the ~~presentation~~pending sale of our ~~consolidated statements of income, primarily to present additional details of revenues~~Norway business (see Note 5), the Angola and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made andNorway businesses are reflected as discontinued operations in all periods presented. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted. Assets and liabilities of these businesses are presented as held for sale in the consolidated ~~financial statements. As a result~~balance sheets as of ~~the reclassifications, general~~December 31, 2013 and ~~administrative expenses for the~~ ~~second quarter~~ ~~and~~ ~~first six months~~ ~~of 2012 increased by~~ ~~$24 million~~ ~~and~~ ~~$63 million~~ which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.June 30, 2014.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation ~~2012~~2013 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of of ~~2013~~2014 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Not Yet Adopted

In ~~June 2013,~~May 2014, the Financial Accounting Standards Board ("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 2017 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 not permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. Examples include disposal of a major geographic area, a major line of business, or a major equity method investment. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations will be 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 are effective for us in the first quarter of 2015 and early adoption is permitted. We are evaluating the provisions of this amendment and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

Recently Adopted

In June 2013, the FASB ratified the Emerging Issues Task Force consensus ~~on Issue 13-C,~~ which requires that an unrecognized tax benefit or(or a portion ~~of an unrecognized tax benefit~~thereof) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update iswas effective for us beginning in the first quarter of 2014 and ~~should~~is required to be applied ~~prospectively to unrecognized tax benefits that exist as~~prospectively. Adoption of ~~the effective date. Early adoption and retrospective application are permitted. We do~~this standard did not ~~expect this accounting standards update to~~ have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States ~~generally accepted accounting principles~~Generally Accepted Accounting Principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update iswas effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.

~~Recently Adopted~~

In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013 and we present the required disclosures in Note 15.applied retrospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 13~~. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.~~

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a ~~wholly-owned~~wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. ~~The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest.~~ Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $3 million recorded at June 30, ~~2013~~2014, consistent with December 31, ~~2012~~2013. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent 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 $~~728~~622 million as of June 30, ~~2013~~2014. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. ~~We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.~~

4. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options, ~~and stock appreciation rights,~~ provided the effect is not antidilutive. The per share calculations below exclude 5 million and 6 million stock options for the second quarters of 2014 and 2013 and 4 million and 6 million stock options for the first six months of 2014 and 2013 as they were antidilutive.


	Three Months Ended June 30,								Three Months Ended June 30,
	2013				2012				2014				2013
(In millions, except per share data)	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
Income from continuing operations									$	360	$	360	$	241	$	241
Discontinued operations									180		180		185		185
Net income	$	426	$	426	$	393	$	393	$	540	$	540	$	426	$	426

Weighted average common shares outstanding	710		710		706		706		676		676		710		710
Effect of dilutive securities	—		4		—		3		—		3		—		4
Weighted average common shares, including
dilutive effect	710		714		706		709		676		679		710		714
Per share:
Income from continuing operations										$0.53		$0.53		$0.34		$0.34
Discontinued operations										$0.27		$0.27		$0.26		$0.26
Net income		$0.60		$0.60		$0.56		$0.56		$0.80		$0.80		$0.60		$0.60



	Six Months Ended June 30,
	2014				2013
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	758	$	758	$	399	$	399
Discontinued operations	931		931		410		410
Net income	$	1,689	$	1,689	$	809	$	809

Weighted average common shares outstanding	684		684		709		709
Effect of dilutive securities	—		4		—		4
Weighted average common shares, including
dilutive effect	684		688		709		713
Per share:
Income from continuing operations	$1.11		$1.10		$0.56		$0.56
Discontinued operations	$1.36		$1.36		$0.58		$0.58
Net income	$2.47		$2.46		$1.14		$1.14

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Six Months Ended June 30,
2013 2012
(In millions, except per share data) Basic Diluted Basic Diluted
Net income $ 809
$ 809
$ 810
$ 810

Weighted average common shares outstanding 709
709
705
705
Effect of dilutive securities —
4
—
4
Weighted average common shares, including
dilutive effect 709
713
705
709
Per share:

Net income $1.14 $1.14 $1.15 $1.14

~~The per share calculations above exclude~~ ~~6 million~~ ~~stock options and stock appreciation rights for the~~ ~~second quarter~~ ~~and~~ ~~first six months~~ of ~~2013. Excluded for the~~ ~~second quarter~~ ~~and~~ ~~first six months~~ of ~~2012~~ ~~were~~ ~~10 million~~ ~~and~~ ~~9 million~~ ~~stock options and stock appreciation rights.~~

5. Dispositions

~~2013~~2014 - ~~North America~~International Exploration and Production ("E&P") Segment

In June 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, with an effective date of January 1, 2014. We expect the transaction to close in the fourth quarter of 2014, pending government and regulatory approvals, with net proceeds of $2.1 billion.

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



	Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2014			2013		2014			2013
Revenues applicable to discontinued operations	$	693		$	828	$	1,373		$	1,732
Pretax income from discontinued operations	$	598		$	662	$	1,130		$	1,422
After-tax income from discontinued operations	$	180	^(a)	$	158	$	322	^(a)	$	380


^(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.

Assets and liabilities presented as held for sale in the June 30, 2014 consolidated balance sheet reflect the Norway business.

In the first quarter of 2014, we closed the sales of our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. A $576 million after-tax gain on the sale of our Angola assets was recorded in the first quarter of 2014. Included in this after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that would have otherwise 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 all periods presented. Select amounts reported in discontinued operations were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2014		2013		2014		2013
Revenues applicable to discontinued operations	$	—	$	79	$	58	$	165
Pretax income from discontinued operations	$	—	$	37	$	51	$	78
After-tax income from discontinued operations	$	—	$	27	$	33	$	30
Pretax gain on disposition of discontinued operations	$	—	$	—	$	470	$	—

Assets and liabilities presented as held for sale in the December 31, 2013 consolidated balance sheet reflect the Angola business.

2014 - North America E&P Segment

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

2013 - North America E&P Segment

In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of ~~$19 million~~.$19 million. A pretax loss of ~~$114~~$114 million was recorded in the second quarter of 2013.

In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A ~~$43~~$43 million pretax loss on this transaction was recorded in the first quarter of 2013.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of ~~$166~~$166 million. A $98 million~~. A~~ ~~$98 million~~ pretax gain was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of ~~$195~~$195 million,, subject to a six-month escrow of ~~$50~~$50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax gain on this sale was ~~$55 million~~.

~~2013 - International E&P Segment~~

~~In June 2013, we entered into an agreement to sell our non-operated~~ ~~10 percent~~ ~~working interest in the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, valued at~~ ~~$1.5 billion~~ ~~before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government, regulatory and third-party approvals. Angola Block 31 is reflected as held for sale in the~~ ~~June 30, 2013~~ ~~consolidated balance sheet as follows:~~$55 million.

(In millions)
Other noncurrent assets $ 1,550
Total assets 1,550
Other current liabilities 58
Deferred credits and other liabilities 39
Total liabilities $ 97

~~2012 - North America E&P Segment~~

~~In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of~~ ~~$206 million~~. This included our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A gain of ~~$166 million~~ ~~was recorded in the first quarter of 2012.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~2012 - International E&P Segment~~

~~In May 2012, we reached an agreement to relinquish our operatorship of and interests in the Bone Bay and Kumawa exploration licenses in Indonesia. A~~ ~~$36 million~~ ~~payment to settle all of our obligations related to these licenses, including well commitments, was accrued and reported as a loss on disposal of assets in the second quarter of 2012.~~

6. Segment Information

Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

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

North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")and methanol, in Equatorial Guinea; 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, ~~as discussed below,~~ 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, net of associated income tax effects.~~activities. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on ~~disposal of assets~~dispositions or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

~~Differences between segment totals and~~As discussed in Note 5, we sold our consolidated totals for income taxes and depreciation, depletion and amortization represent amounts related to corporate administrative activities and other unallocated items which are included in “Items not allocated to segments, net of income taxes”Angola assets in the ~~reconciliation below. Total capital expenditures include accruals but not corporate activities.~~first quarter of 2014 and entered into an agreement to sell our Norway business in June 2014. The Angola and Norway businesses are reflected as discontinued operations and are excluded from the International E&P segment in all periods presented.


									Three Months Ended June 30, 2014
	Three Months Ended June 30, 2013														Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		Total		N.A. E&P		Int'l E&P		OSM		to Segments				Total
Revenues:
Sales and other operating revenues	$	1,284	$	1,732	$	353	$	3,369	$	1,540	$	347	$	383	$	—			$	2,270
Marketing revenues	439		51		9		499		540		61		17		—				618
Segment revenues	$	1,723	$	1,783	$	362	3,868
Unrealized gain on crude oil derivative instruments							50
Total revenues							$	3,918	2,080		408		400		—				2,888
Segment income	$	221	$	382	$	20	$	623
Income from equity method investments	—		77		—		77		—		120		—		—				120
Net gain (loss) on disposal of assets and other income									15		15		1		(98		)		(67		)
Less:
Production expenses									217		99		246		—				562
Marketing costs									537		60		17		—				614
Exploration expenses									82		63		—		—				145
Depreciation, depletion and amortization	490		189		48		727		550		75		45		10				680
Income tax provision	129		1,004		7		1,140
Capital expenditures	904		241		97		1,242
Impairments									4		—		—		—				4
Other expenses ^(a)									126		34		13		67			^(c)	240
Taxes other than income									102		—		6		1				109
Net interest and other									—		—		—		76				76
Income tax provision (benefit)									175		52		19		(95		)		151
Segment income/Income from continuing operations									$	302	$	160	$	55	$	(157	)		$	360
Capital expenditures ^(b)									$	1,102	$	115	$	55	$	10			$	1,282


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


^(b)	Includes accruals.


^(c)	Includes pension settlement loss of $8 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


									Three Months Ended June 30, 2013
	Three Months Ended June 30, 2012														Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		Total		N.A. E&P		Int'l E&P		OSM		to Segments				Total
Revenues:
Sales and other operating revenues	$	833	$	1,813	$	329	$	2,975	$	1,284	$	826	$	353	$	50		^(c)	$	2,513
Marketing revenues	696		56		5		757		439		49		9		—				497
Total revenues	$	1,529	$	1,869	$	334	$	3,732	1,723		875		362		50				3,010
Segment income	$	70	$	373	$	50	$	493
Income from equity method investments	—		60		—		60		—		77		—		—				77
Net gain (loss) on disposal of assets and other income									6		7		3		(113		)		(97		)
Less:
Production expenses									195		83		274		—				552
Marketing costs									438		47		9		—				494
Exploration expenses									76		49		—		—				125
Depreciation, depletion and amortization	290		228		50		568		490		77		48		11				626
Income tax provision	39		1,070		17		1,126
Capital expenditures	1,013		202		43		1,258
Other expenses ^(a)									94		21		2		112			^(d)	229
Taxes other than income									86		—		5		2				93
Net interest and other									—		—		—		67				67
Income tax provision (benefit)									129		512		7		(85		)		563
Segment income/Income from continuing operations									$	221	$	170	$	20	$	(170	)		$	241
Capital expenditures ^(b)									$	904	$	107	$	98	$	10			$	1,119

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

(b)Includes accruals.

(c)Unrealized gain on crude oil derivative instruments.

(d)Includes pension settlement loss of $17 million


									Six Months Ended June 30, 2014
	Six Months Ended June 30, 2013														Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		Total		N.A. E&P		Int'l E&P		OSM		to Segments				Total
Revenues:
Sales and other operating revenues	$	2,499	$	3,619	$	741	$	6,859	$	2,932	$	727	$	760	$	—			$	4,419
Marketing revenues	784		136		9		929		980		131		48		—				1,159
Segment revenues	$	3,283	$	3,755	$	750	7,788
Unrealized loss on crude oil derivative instruments							—
Total revenues							$	7,788	3,912		858		808		—				5,578
Segment income	$	162	$	835	$	58	$	1,055
Income from equity method investments	—		195		—		195		—		257		—		—				257
Net gain (loss) on disposal of assets and other income									18		32		3		(98		)		(45		)
Less:
Production expenses									428		199		477		—				1,104
Marketing costs									977		131		48		—				1,156
Exploration expenses									139		79		—		—				218
Depreciation, depletion and amortization	968		396		100		1,464		1,065		146		90		22				1,323
Income tax provision	99		2,146		20		2,265
Capital expenditures	1,874		466		142		2,482
Impairments									21		—		—		—				21
Other expenses ^(a)									236		72		26		196			^(c)	530
Taxes other than income									192		—		11		1				204
Net interest and other									—		—		—		125				125
Income tax provision (benefit)									328		139		40		(156		)		351
Segment income/Income from continuing operations									$	544	$	381	$	119	$	(286	)		$	758
Capital expenditures ^(b)									$	1,969	$	220	$	123	$	13			$	2,325

Six Months Ended June 30, 2012
(In millions) N.A. E&P Int'l E&P OSM Total
Revenues:
Sales and other operating revenues $ 1,745
$ 3,476
$ 698
$ 5,919
Marketing revenues 1,471
120
15
1,606
Total revenues $ 3,216
$ 3,596
$ 713
$ 7,525
Segment income $ 174
$ 780
$ 88
$ 1,042
Income from equity method investments 1
137
—
138
Depreciation, depletion and amortization 604
428
99
1,131
Income tax provision 100
2,041
30
2,171
Capital expenditures 1,842
340
95
2,277

~~The following reconciles total revenues to sales and other operating revenues as reported in the consolidated statements of income:~~

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2013 2012 2013 2012
Total revenues $ 3,918
$ 3,732
$ 7,788
$ 7,525
Less: Marketing revenues 499
757
929
1,606
Sales and other operating revenues, including related party $ 3,419
$ 2,975
$ 6,859
$ 5,919


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


^(b)	Includes accruals.


^(c)	Includes pension settlement loss of $71 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~The following reconciles segment income to net income as reported in the consolidated statements of income:~~

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2013 2012 2013 2012
Segment income $ 623
$ 493
$ 1,055
$ 1,042
Items not allocated to segments, net of income taxes:

Corporate and other unallocated items (156 ) (77 ) (227 ) (148 )
Unrealized gain (loss) on crude oil derivative instruments 32
—
—
—
Net gain (loss) on dispositions (73 ) (23 ) (9 ) 83
Impairments —
—
(10 ) (167 )
Net income $ 426
$ 393
$ 809
$ 810



	Six Months Ended June 30, 2013
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	2,499	$	1,721	$	741	$	—			$	4,961
Marketing revenues	784		136		9		—				929
Total revenues	3,283		1,857		750		—				5,890
Income from equity method investments	—		195		—		—				195
Net gain (loss) on disposal of assets and other income	6		23		3		(11		)		21
Less:
Production expenses	379		161		545		—				1,085
Marketing costs	785		133		9		—				927
Exploration expenses	511		71		—		—				582
Depreciation, depletion and amortization	968		168		100		21				1,257
Impairments	23		—		—		15				38
Other expenses ^(a)	200		64		10		216			^(c)	490
Taxes other than income	162		—		11		2				175
Net interest and other	—		—		—		140				140
Income tax provision (benefit)	99		1,035		20		(141		)		1,013
Segment income/Income from continuing operations	$	162	$	443	$	58	$	(264	)		$	399
Capital expenditures ^(b)	$	1,874	$	194	$	143	$	40			$	2,251


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


^(b)	Includes accruals.


^(c)	Includes pension settlement loss of $17 million.

7. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:


	Three Months Ended June 30,												Three Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2013			2012			2013			2012			2014			2013			2014			2013
Service cost	$	14		$	13		$	1		$	1		$	11		$	13		$	1		$	1
Interest cost	16			16			3			3			15			16			3			3
Expected return on plan assets	(16		)	(16		)	—			—			(14		)	(16		)	—			—
Amortization:
– prior service cost (credit)	1			2			(1		)	(1		)	2			1			(1		)	(1		)
– actuarial loss	16			13			—			—			10			16			—			—
Net settlement loss^(a)	17			—			—			—			8			17			—			—
Net periodic benefit cost	$	48		$	28		$	3		$	3		$	32		$	47		$	3		$	3

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Six Months Ended June 30,												Six Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2013			2012			2013			2012			2014			2013			2014			2013
Service cost	$	28		$	25		$	2		$	2		$	23		$	26		$	2		$	2
Interest cost	31			32			6			7			31			31			6			6
Expected return on plan assets	(33		)	(32		)	—			—			(32		)	(33		)	—			—
Amortization:
– prior service cost (credit)	3			4			(3		)	(3		)	3			3			(2		)	(3		)
– actuarial loss	29			25			—			—			16			29			—			—
Net settlement loss^(a)	17			—			—			—			71			17			—			—
Net periodic benefit cost	$	75		$	54		$	5		$	6		$	112		$	73		$	6		$	5

(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. Such settlements were recorded for our U.S. plans in the ~~second quarter~~ ~~of 2013.~~


^(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.

During the first and second quarters of 2014 and the second quarter of 2013, we recorded the effects of partial settlements of our United States ("U.S.") pension plans and we remeasured the ~~plans'~~plans’ assets and liabilities as of ~~June 30, 2013, using a discount rate of~~ ~~4.14 percent~~ ~~as of that date.~~the applicable balance sheet dates. As a result, we recognized pretax decreases of $68 million and $32 million in actuarial losses in other comprehensive income for the second quarter and first six months of 2014 and a pretax decrease of $139 million in actuarial losses in other comprehensive ~~income.~~income for the second quarter and first six months of 2013.

During the first six months of ~~2013~~2014, we made contributions of $2837 million to our funded pension plans. We expect to make additional contributions up to an estimated $3952 million to our funded pension plans over the remainder of ~~2013~~2014. Current benefit payments related to unfunded pension and other postretirement benefit plans were $1047 million and $78 million during the first six months of ~~2013~~2014.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

8. Income Taxes

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 provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments ~~and to individual items not allocated to segments~~ is reported in ~~“Corporate and other unallocated items”~~the “Not Allocated to Segments” column of the tables in Note 6.

Our effective income tax rates on continuing operations for the first six months of 2014 and 2013 were 32 percent and 72 percent. The decrease in the effective tax rate on continuing operations in the first six months of ~~2013~~2014 ~~and 2012 were~~ ~~72 percent~~ ~~and~~ ~~71 percent. These rates are higher than the U.S. statutory rate of~~ ~~35 percent~~is primarily due to ~~earnings~~a decrease in pretax income from ~~foreign jurisdictions, primarily Norway and~~ Libya operations, where the ~~tax rates are in excess of the U.S. statutory rate. In Libya, where the statutory~~ tax rate is in excess of 90 percent. In Libya, we have had no oil liftings since July 2013 due to third-party labor strikes at the Es Sider oil terminal.

The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the 90first six months of 2014 and 2013. Excluding Libya, the effective tax rates on continuing operations would be 34 percent and 39 percent for the ,first six months of 2014 and 2013. In Libya, there remains uncertainty around ~~sustained~~future production and sales levels. Reliable estimates of 2014 and 2013 ~~and 2012~~Libyan annual ordinary income from our ~~Libyan~~ operations could not be made and the range of possible scenarios ~~when including ordinary income from our Libyan operations~~ in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the first six months of ~~2013~~2014 and ~~2012,~~2013, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income excluding ~~Libya~~Libya.

We have reviewed our foreign operations, including the disposition of Norway, and concluded that our foreign operations do not have the same level of immediate capital needs as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of $746 million associated with our United Kingdom ("U.K.") operations to be permanently reinvested outside the U.S. Foreign tax credits associated with these earnings would be sufficient to offset any incremental U.S. tax liabilities. The remaining undistributed income of certain consolidated foreign subsidiaries for which no U.S. deferred income tax provision ~~applicable~~has been recorded because we intend to ~~Libyan ordinary~~permanently reinvest such income in our foreign operations amounted to $862 million at June 30, 2014. If such income was ~~recorded as a discrete item in the periods. Excluding Libya, the effective~~not permanently reinvested, income tax ~~rates~~expense of approximately $302 million would be ~~63 percent~~ ~~and~~ ~~64 percent~~ ~~for the~~ ~~first six months~~recorded, not including potential utilization of ~~2013~~ ~~and 2012.~~

~~9. Inventories~~

~~Inventories are carried at the lower of cost or market value.~~

June 30, December 31,
(In millions) 2013 2012
Liquid hydrocarbons, natural gas and bitumen $ 48
$ 73
Supplies and other items 320
288
Inventories, at cost $ 368
$ 361

~~10. Property, Plant and Equipment~~

June 30, December 31,
(In millions) 2013 2012
North America E&P $ 25,129
$ 23,748
International E&P 12,213
13,214
Oil Sands Mining 10,270
10,127
Corporate 484
449
Total property, plant and equipment 48,096
47,538
Less accumulated depreciation, depletion and amortization (20,639 ) (19,266 )
Net property, plant and equipment $ 27,457
$ 28,272

In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed. Since that time, average sales volumes have increased to near pre-conflict levels. We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains. As of ~~June 30, 2013, our net property, plant and equipment investment in Libya was approximately~~ ~~$740 million~~.

~~Exploratory well costs capitalized greater than one year after completion of drilling were~~ ~~$220 million~~ ~~as of~~ ~~June 30, 2013. The net decrease from~~ ~~December 31, 2012~~ ~~primarily related to the conveyance of our interests in the Marcellus natural gas shale play to the operator in February 2013.~~foreign tax credits.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. Inventories

Inventories are carried at the lower of cost or market value.



	June 30,		December 31,
(In millions)	2014		2013
Liquid hydrocarbons, natural gas and bitumen	$	100	$	55
Supplies and other items	304		309
Inventories, at cost	$	404	$	364

10. Property, Plant and Equipment



	June 30,		December 31,
(In millions)	2014		2013
North America E&P	$	15,595	$	14,973
International E&P^(a)	2,617		3,590
Oil Sands Mining	9,494		9,447
Corporate	118		135
Net property, plant and equipment	$	27,824	$	28,145


^(a)	International E&P decrease is due to Norway assets reflected as held for sale in the June 30, 2014 consolidated balance sheet.

Beginning in the third quarter of 2013, our Libya operations have been impacted by on-going third-party labor strikes at the Es Sider oil terminal. In early July 2014, Libya's National Oil Corporation rescinded force majeure associated with these third-party labor strikes. However, liftings have yet to resume and there remains uncertainty around future production and sales levels. As of June 30, 2014, our net property, plant and equipment investment in Libya is approximately $772 million. 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.

Exploratory well costs capitalized greater than one year after completion of drilling were $102 million as of June 30, 2014 (including $44 million related to Norway project costs which are reflected in noncurrent assets held for sale) and $281 million as of December 31, 2013 (including $70 million related to Norway project costs). This $179 million net decrease was the result of a $153 million reduction due to the sale of our interests in Angola Blocks 31 and 32 and a decrease of $26 million due to the commencement of drilling at the Boyla development offshore Norway.

11. Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations during the first six months of ~~2013:~~2014:


(In millions)
Beginning balance	$	1,783		$	2,096
Incurred, including acquisitions	8			31
Settled, including dispositions	(27		)	(96		)
Accretion expense (included in depreciation, depletion and amortization)	48			66
Revisions to previous estimates	306			41
Held for sale	(39		)	(309		)
Ending balance^(a)	$	2,079		$	1,829

^(a) Includes asset retirement obligations of ~~$40~~$25 million classified as a short-term at June 30, ~~2013~~2014.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, ~~2013~~2014 and December 31, ~~2012~~2013 by fair value hierarchy level.


	June 30, 2013										June 30, 2014
(In millions)	Level 1		Level 2		Level 3		Collateral		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	—	$	52
Interest rate	—		6		—		—		6		$	—	$	11	$	—	$	11
Derivative instruments, assets	$	—	$	58	$	—	$	—	$	58	$	—	$	11	$	—	$	11
Derivative instruments, liabilities
Foreign currency	$	—	$	30	$	—	$	—	$	30	$	—	$	12	$	—	$	12
Derivative instruments, liabilities	$	—	$	30	$	—	$	—	$	30	$	—	$	12	$	—	$	12

December 31, 2012
(In millions) Level 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets
Commodity $ —
$ 52
$ —
$ 1
$ 53
Interest rate —
21
—
—
21
Foreign currency —
18
—
—
18
Derivative instruments, assets $ —
$ 91
$ —
$ 1
$ 92

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities. Commodity options in Level 2 are valued using the Black-Scholes Model. Inputs to this model include prices as noted above, discount factors, and implied market volatility. The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments. Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.



	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8
Foreign currency	—		2		—		2
Derivative instruments, assets	$	—	$	10	$	—	$	10
Derivative instruments, liabilities
Foreign currency	$	—	$	4	$	—	$	4
Derivative instruments, liabilities	$	—	$	4	$	—	$	4

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs. Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

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 June 30,								Three Months Ended June 30,
	2013				2012				2014				2013
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	—	$	—	$	1	$	—	$	4	$	—	$	—


	Six Months Ended June 30,								Six Months Ended June 30,
	2013				2012				2014				2013
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	38	$	75	$	263	$	—	$	21	$	—	$	38

All long-lived assets held for use that were impaired in the first six months of ~~2013~~2014 and ~~2012~~2013 were held by our North America E&P segment. The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The Ozona development in the Gulf of Mexico ceased producing in the first quarter of 2013 and a $21 million impairment was recorded. In the first and second quarters of 2014, we recorded additional impairments of $17 million and $4 million as a result of estimated abandonment cost revisions.

In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.

In early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of our future production as well as our reserves and an impairment of ~~$261 million~~ was recorded in the first quarter of 2012. As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional ~~$21 million~~ ~~impairment was recorded.~~

Other impairments of long-lived assets held for use by our North America E&P segment in the first six months of 2013 ~~and~~ ~~2012~~ were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at June 30, ~~2013~~2014 and December 31, ~~2012~~2013.


	June 30, 2013				December 31, 2012				June 30, 2014				December 31, 2013
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	165	$	164	$	189	$	186	$	166	$	159	$	154	$	147
Total financial assets	165		164		189		186		166		159		154		147
Financial liabilities
Other current liabilities	13		13		13		13		13		13		13		13
Long-term debt, including current portion^(a)	6,991		6,460		7,610		6,642		7,133		6,394		6,922		6,427
Deferred credits and other liabilities	141		140		94		94		93		147		149		147
Total financial liabilities	$	7,145	$	6,613	$	7,717	$	6,749	$	7,239	$	6,554	$	7,084	$	6,587

^(a) Excludes capital leases.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

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. ~~Because these quotes cannot be independently verified to an active market they are considered Level 3 inputs.~~ 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.

13. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 12. 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. Netting is assessed by counterparty, and as of June 30, ~~2013~~2014 and December 31, ~~2012~~2013, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of June 30, ~~2013~~2014 and December 31, ~~2012~~2013.

June 30, 2013
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Interest rate $ 6
$ —
$ 6
Other noncurrent assets
Total Designated Hedges 6
—
6

Not Designated as Hedges
     Commodity 52
—
52
Other current assets
Total Not Designated as Hedges 52
—
52

     Total $ 58
$ —
$ 58

June 30, 2013
(In millions) Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges
Foreign currency $ —
$ 30
$ 30
Other current liabilities
Total Designated Hedges —
30
30

Total $ —
$ 30
$ 30

December 31, 2012
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Foreign currency $ 18
$ —
$ 18
Other current assets
     Interest rate 21
—
21
Other noncurrent assets
Total Designated Hedges 39
—
39

Not Designated as Hedges
     Commodity 52
—
52
Other current assets
Total Not Designated as Hedges 52
—
52

     Total $ 91
$ —
$ 91

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	June 30, 2014
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	11	$	—	$	11	Other noncurrent assets
Total Designated Hedges	$	11	$	—	$	11



	June 30, 2014
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	12	$	12	Current liabilities held for sale
Total Designated Hedges	$	—	$	12	$	12



	December 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Foreign currency	2		—		2		Other current assets
Total Designated Hedges	$	10	$	—	$	10

	December 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	4	$	4	Other current liabilities
Total Designated Hedges	$	—	$	4	$	4

Derivatives Designated as Fair Value Hedges

AsThe following table presents by maturity date, information about our interest rate swap agreements as of June 30, ~~2013~~2014 and December 31, ~~2012, we had multiple interest rate swap agreements with a total notional amount of~~ ~~$600 million~~ ~~with a maturity date of October 1, 2017 at a~~2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating ~~rate of~~ rate.~~4.68 percent~~ ~~and~~ ~~4.70 percent~~.



	Aggregate Notional		June 30, 2014		December 31, 2013
	Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate
October 1, 2017	$	600	4.64	%	4.65	%
March 15, 2018	$	300	4.48	%	4.50	%

As of June 30, ~~2013~~2014 and December 31, ~~2012~~2013, our foreign currency forwards had an aggregate notional amount of ~~2,965~~2,870 million and ~~3,043~~2,387 million Norwegian Kroner at a weighted average forward ~~rate~~rates of ~~5.738~~6.003 and ~~5.780~~.6.060. These forwards hedge our current Norwegian tax liability and those outstanding at June 30, 2014 have settlement dates through ~~December 2013~~October 2014.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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


		Gain (Loss)													Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	Income Statement Location	2013			2012			2013			2012			Income Statement Location	2014			2013			2014			2013
Derivative
Interest rate	Net interest and other	$	(12	)	$	12		$	(15	)	$	12		Net interest and other	$	4		$	(12	)	$	3		$	(15	)
Foreign currency	Provision for income taxes	$	(21	)	$	(32	)	$	(46	)	$	(40	)	Discontinued operations	$	(14	)	$	(21	)	$	(11	)	$	(46	)
Hedged Item
Long-term debt	Net interest and other	$	12		$	(12	)	$	15		$	(12	)	Net interest and other	$	(4	)	$	12		$	(3	)	$	15
Accrued taxes	Provision for income taxes	$	21		$	32		$	46		$	40		Discontinued operations	$	14		$	21		$	11		$	46

Derivatives not Designated as Hedges

~~In August 2012, we entered into crude oil derivatives related to a portion~~The impact of ~~our forecast North America E&P crude oil sales through December 31, 2013. These~~all commodity ~~derivatives were not designated as hedges and are shown in the table below.~~

Remaining Term Bbls per Day Weighted Average Price per Bbl Benchmark
Swaps
July 2013 - December 2013 20,000 $96.29 West Texas Intermediate
July 2013 - December 2013 25,000 $109.19 Brent
Option Collars
July 2013 - December 2013 15,000 $90.00 floor / $101.17 ceiling West Texas Intermediate
July 2013 - December 2013 15,000 $100.00 floor / $116.30 ceiling Brent

~~The following table summarizes the effect of all~~ derivative instruments not designated as hedges appears in sales and other operating revenues in our consolidated statements of ~~income.~~income and were net gains of $67 million and $13 million in the second quarter and first six months of 2013.

Gain (Loss)
Three Months Ended Six Months Ended
June 30, June 30,
(In millions) Income Statement Location 2013 2012 2013 2012
Commodity Sales and other operating revenues, including related party $ 67
$ (1 ) $ 13
$ 2

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

14. 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 six months of ~~2013~~2014:

Stock Options Restricted Stock

Number of
Shares

Weighted
Average
Exercise Price
Awards
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 2012 19,536,965

$26.19
4,177,884

$29.02
Granted 1,381,321
^(a)

$32.85
1,087,731

$32.38
Options Exercised/Stock Vested (1,422,488 )

$21.53
(605,209 )
$29.73
Cancelled (386,186 )

$34.54
(182,958 )
$29.35
Outstanding at June 30, 2013 19,109,612

$26.85
4,477,448

$29.79



	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013	18,104,887				$27.27	4,031,888			$31.80
Granted	1,935,423		^(a)		$34.48	1,887,487			$34.84
Options Exercised/Stock Vested	(3,800,690	)			$20.15	(694,785	)		$33.10
Canceled	(440,429	)			$34.14	(319,737	)		$31.65
Outstanding at June 30, 2014	15,799,191				$29.68	4,904,853			$32.79

^(a) The weighted average grant date fair value of stock option awards granted was $~~10.25~~10.50 per share.

~~Performance~~Stock-based performance unit awards

In During the first ~~quarter~~six months of ~~2013,~~2014, we granted ~~353,600~~221,491 stock-based performance units to certain ~~officers~~officers. The grant date fair value per unit was $34.28.

15. Debt

As of June 30, 2014, we had no borrowings against our revolving credit facility, as described below, or under our U.S. commercial paper program that ~~provide~~is backed by the revolving credit facility.

In May 2014, we amended our $2.5 billion unsecured revolving credit facility (the "Credit Facility"), including an extension of the maturity to May 2019. Terms of this amended Credit Facility include the ability to request two one-year extensions and an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million. Fees on the unused commitment of each lender range from 8 basis points to 22.5 basis points depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) an adjusted LIBOR rate plus a ~~cash payout upon~~margin ranging from 87.5 basis points to 150 basis points depending on our credit ratings or (b) the ~~achievement~~Base Rate plus a margin ranging from 0 basis points to 50 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of ~~certain performance goals at~~(a) the ~~end~~prime rate, (b) the federal funds rate plus one-half of ~~a 36-month performance period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR~~one percent or (c) LIBOR for a ~~group~~one-month interest period plus 1 percent.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The agreement contains a covenant that requires our ratio of ~~peer companies determined by the Compensation Committee~~total debt to total capitalization not to exceed 65 percent as of the ~~Board~~last day of ~~Directors. At~~each fiscal quarter. If an event of default occurs, the ~~grant date, each unit represents the value of~~ ~~one~~ ~~share of our common stock, while payout after completion~~lenders holding more than half of the ~~performance period will be based on~~commitments may terminate the ~~value~~commitments under the Credit Facility and require the immediate repayment of ~~anywhere from~~ ~~zero~~ to ~~two~~ ~~times~~all outstanding borrowings and the ~~number~~cash collateralization of ~~units granted. Dividend equivalents accrue during~~all outstanding letters of credit under the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units. The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method. These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.Credit Facility.

~~15.~~16. Reclassifications Out of Accumulated Other Comprehensive Loss

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


	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013				Three Months Ended June 30,						Six Months Ended June 30,
(In millions)							Income Statement Line	2014			2013			2014			2013			Income Statement Line
Accumulated Other Comprehensive Loss Components	Accumulated Other Comprehensive Loss Components							Accumulated Other Comprehensive Loss Components
	Income (Expense)							Income (Expense)
Amortization of postretirement and postemployment plans
Actuarial loss	$	(16	)	$	(29	)	General and administrative
Postretirement and postemployment plans								Postretirement and postemployment plans
Amortization of actuarial loss								$	(10	)	$	(16	)	$	(16	)	(29		)	General and administrative
Net settlement loss	(17		)	(17		)	General and administrative	(8		)	(17		)	(71		)	(17		)	General and administrative
	12			17			Provision for income taxes	(18		)	(33		)	(87		)	(46		)	Income from operations
Total reclassifications for the period	$	(21	)	$	(29	)	Net income
								7			12			30			17			Provision for income taxes
Other insignificant, net of tax								—			—			(1		)	—
Total reclassifications								$	(11	)	$	(21	)	$	(58	)	$	(29	)	Income from continuing operations

17. Stockholders' Equity

~~MARATHON OIL CORPORATION~~During the first six months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program, 13 million of which were acquired in the second quarter of 2014 at a cost of $449 million.

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~16.~~18. Supplemental Cash Flow Information


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2013			2012			2014			2013
Net cash provided from operating activities:
Net cash provided by operating activities:
Interest paid (net of amounts capitalized)	$	160		$	113		$	149		$	160
Income taxes paid to taxing authorities(a)	2,474			2,317			1,336			2,474
Commercial paper, net:
Commercial paper - issuances	$	2,075		$	4,252
- repayments	(2,275		)	(3,702		)
Noncash investing activities:
Issuances							$	2,285		$	2,075
Repayments							(2,420		)	(2,275		)
Commercial paper, net							(135		)	(200		)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	314		$	34		$	42		$	309
Debt payments made by United States Steel	—			14
Change in capital expenditure accrual	(149		)	159			95			(154		)
Asset retirement obligations assumed by buyer	92			7			52			92
Receivable for disposal of assets	50			—			44			50


^(a)	Income taxes paid to taxing authorities included $1,076 million and $1,392 million related to discontinued operations in the first six months of 2014 and 2013.

~~17.~~19. 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. ~~Certain of these matters are discussed below.~~

~~Litigation~~– In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Contractual commitments – At June 30, ~~2013~~2014, Marathon’s contract commitments to acquire property, plant and equipment were ~~$1,122 million~~.$1,209 million.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

We are ~~an international~~a global energy company based in Houston, Texas, with operations in ~~the United States, Canada,~~North America, Europe, Africa and the Middle ~~East and Europe.~~East. We have three reportable operating segments. Each of these segments is organized ~~and managed~~ based upon both geographic location and the nature of the products and services it offers.

North America ~~Exploration and Production ("~~E~~&P")~~&P – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial ~~Guinea;~~Guinea ("E.G."); and

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

~~Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion~~ As discussed in Note 5 to the consolidated financial statements, our Angola and ~~Analysis of Financial Condition~~Norway businesses are reflected as discontinued operations and ~~Results of Operations contain forward-looking statements concerning trends or events potentially affecting~~are excluded from the International E&P segment in all periods presented. We sold our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forthAngola assets in the ~~forward-looking statements. For additional risk factors affecting~~first quarter of 2014 and entered into an agreement to sell our Norway business ~~see Item 1A. Risk Factors~~ in ~~our 2012 Annual Report on Form 10-K. We assume no duty~~June 2014 in a transaction expected to ~~update~~close in the fourth quarter of 2014. Assets and liabilities of these ~~statements~~businesses are presented as ~~to any future date.~~held for sale in the consolidated balance sheets as of December 31, 2013 and June 30, 2014.

Executive Summary

Our net sales volumes from continuing operations for the second quarter and first six months of2014 averaged 394 thousand barrels of oil equivalent per day ("mboed") and 390 mboed compared to 410 mboed and 418 mboed for the second quarter and first six months of2013. Since we had no oil liftings from Libya in the second quarter and first six months of2014 as a result of third-party labor strikes at the Es Sider oil terminal, a more representative comparison is net sales volumes from continuing operations excluding Libya. Excluding Libya, our net sales volumes from continuing operations averaged 361 mboed and 375 mboed for the second quarter and first six months of2013, representing increases in net sales volume of 9 percent and 4 percent in the second quarter and first six months of2014. The continued ramp up of production from our U.S. resource plays was the most significant contributor to the 2014 increases when comparing results excluding Libya. Net sales volumes related to the Angola and Norway discontinued operations for the second quarter and first six months of2014 averaged 70 mboed and 73 mboed compared to 96 mboed and 97 mboed for the second quarter and first six months of2013, ranging from 15 to 19 percent of total company net sales volumes in those periods.

Net income per diluted share was $0.80 and $2.46 for the second quarter and first six months of 2014, increases of 33 percent and 116 percent over the same periods of 2013, reflecting higher income from our North America E&P and Oil Sands Mining segments driven primarily by higher commodity prices and growth in net sales volumes from our U.S. resource plays. The increase for the first six months of 2014 also reflects the $0.83 per diluted share after-tax gain on the sale of our Angola assets in the first quarter of 2014 and non-cash unproved property impairments on Eagle Ford leases that either expired or that we did not expect to drill or extend in the first quarter of 2013.

Key Operating and Financial Activities

In the second quarter of ~~2013~~2014, notable ~~items~~activities were:

~~Total~~Increased net ~~sales volumes averaged~~ ~~506~~ ~~thousand barrels of oil equivalent~~income per ~~day (“mboed”), a~~ ~~12 percent~~ ~~increase over~~diluted share to $0.80 compared to $0.60 for the same quarter of ~~last year~~

2013

~~North America E&P net sales volumes increased 38 percent over~~Increased income from continuing operations per diluted share to $0.53 compared to $0.34 for the same quarter of ~~last year~~2013

~~Eagle Ford shale averaged~~Increased average net sales volumes from the three U.S. resource plays to 170 mboed, up 29 percent from same quarter of ~~80 mboed,~~last year, with liquid hydrocarbon production up more than 30 percent

Executed agreements to add approximately 30,000 net acres to our Oklahoma resource position, increasing total net acreage to more than 300,000 net acres

•Recorded 98 percent average operational availability for operated assets

Reached definitive agreement to sell Norway business for a total transaction value of $2.7 billion; expect to close in the fourth quarter of 2014 with net proceeds of $2.1 billion

Repurchased approximately 13 million common shares at a cost of $449 million leaving $1.5 billion remaining on the share repurchase authorization

Significant third quarter activity through ~~286 percent~~August 5, 2014 ~~increase~~includes:

Increased quarterly dividend by 11 percent to $0.21 per share

Operations

North America E&P--Production



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Bakken	44	35	41	34
Eagle Ford	67	50	65	48
Oklahoma resource basins	2	1	2	1
Other North America	38	40	36	41
Total Crude Oil and Condensate	151	126	144	124
Natural Gas Liquids (mbbld)
Bakken	3	2	2	2
Eagle Ford	16	14	16	13
Oklahoma resource basins	6	4	5	4
Other North America	2	2	4	2
Total Natural Gas Liquids	27	22	27	21
Total Liquid Hydrocarbons (mbbld)
Bakken	47	37	43	36
Eagle Ford	83	64	81	61
Oklahoma resource basins	8	5	7	5
Other North America	40	42	40	43
Total Liquid Hydrocarbons	178	148	171	145
Natural Gas (mmcfd)
Bakken	18	12	17	13
Eagle Ford	111	99	109	91
Oklahoma resource basins	61	48	58	49
Other North America	104	157	113	175
Total Natural Gas	294	316	297	328
Equivalent Barrels (mboed)
Bakken	50	39	46	38
Eagle Ford	102	81	99	76
Oklahoma resource basins	18	13	17	13
Other North America	57	68	58	73
Total North America E&P	227	201	220	200

~~Bakken shale averaged~~North America E&P segment average net sales volumes of 39 ~~mboed, a~~ ~~49 percent~~ ~~increase~~

~~Turnaround~~ in ~~Equatorial Guinea started and safely completed in April, eight days ahead of schedule and below budget~~

~~Successful appraisal well on non-operated Gunflint prospect in the Gulf of Mexico announced by operator~~

~~Two Gulf of Mexico leases from Lease Sale 227 awarded to us~~

~~Entered into agreement to sell our working interest in Angola Block 31 in a transaction valued at $1.5 billion before closing adjustments~~

~~Concluded exploration activities in Poland~~

~~Closed sale of interests in DJ Basin and recorded a $114 million loss on sale~~

~~Some significant third quarter activities to~~ ~~August 8, 2013~~ ~~include:~~

~~Increased dividend 12 percent to 19 cents per share~~

~~Overview and Outlook~~

~~North America E&P~~

~~Production~~

~~Net liquid hydrocarbon and natural gas sales volumes averaged~~ ~~201~~ ~~mboed and~~ ~~200~~ ~~mboed during~~ the second quarter and first six months of2014 increased 13 percent and 10 percent when compared to the second quarter and first six months of2013 ~~compared to~~ ~~146~~ ~~mboed in both periods of~~ ~~2012, for increases of approximately 37 percent in both periods.~~. Net liquid hydrocarbon sales volumes ~~increased~~increased 30 thousand barrels per day ("mbbld") and 26 mbbld for ~~both~~ thesecond quarter and ~~the~~ first six months of ~~2013,~~2014, primarily reflecting ~~the~~continued growth across our three U.S. resource plays, partially offset by natural declines in Gulf of Mexico production. The negative impact of ~~our ongoing development programs~~extreme winter weather on availability and completion operations in the ~~Eagle Ford and Bakken shale resource plays, while net~~first quarter of 2014 is reflected in the smaller increase for the six-month period. Net natural gas sales volumes decreased ~~slightly~~7 percent and 9 percent during the same periods due primarily to the cessation of production from operated wells in the Powder River Basin in Wyoming and to the sale of our Alaska assets in January ~~2013. Excluding the sales volume related to Alaska~~2013, somewhat offset by increases in ~~both six-month periods, our average net liquid hydrocarbon and~~associated natural gas ~~sales volumes increased 50 percent.~~production from our U.S. resource plays.

Eagle Ford – ~~In 2013, production growth continued in the Eagle Ford shale play.~~ Average net sales volumes from Eagle Ford were 80102 mboed and 7699 mboed in the second quarter and first six months of2014 ~~of 2013~~ compared to 2181 mboed and 1876 mboed in the same periods of ~~2012.~~2013, for increases of 26 percent and 30 percent. Approximately 6366 percent of ~~the~~ ~~first six months of 2013~~ ~~production was~~second quarter sales were crude oil and condensate, 1716 percent was natural gas liquids ("NGLs") and 2018 percent was natural gas. In

Enhanced completion design in the ~~second~~Eagle Ford is delivering strong early results. Wells with 180-day cumulative production are yielding on average 25 percent improvement relative to modeled type curves. The pace of execution continued to improve along with the transition to higher density pad drilling, as evidenced by the 55 percent increase in the number of wells brought to sales compared to the first quarter of 2013, we increased the amount of crude oil and condensate transported by pipeline to 70 percent from 65 percent in the previous quarter. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.

2014. During the second quarter of ~~2013~~2014, we reached total depth on 8288 gross operated wells and brought 7076 gross operated wells to sales ~~with 158 gross operated wells~~compared to 82 reaching total depth and ~~138 gross operated wells~~79 brought ~~on line~~to sales in the second quarter of 2013. During the first six months of ~~2013~~2014, we reached total depth on 171 gross operated wells and brought 125 gross operated

wells to sales compared to 158 reaching total depth and 148 brought to sales in the same period of 2013. Our ~~. With approximately 85 percent pad drilling, which continues to improve efficiencies and reduce costs, our~~ second quarter of 2014 average spud-to-total depth time was 13 days compared to 12 days ~~and spud-to-spud was 18 days.~~

~~To support production growth across the Eagle Ford operating area, approximately 170 miles of gathering lines were installed~~ in the same period of ~~first six months of~~ 2013, bringing the total to more than 650 miles. We also commissioned six new central gathering and treating facilities and have three additional facilities in various stages of planning or construction, bringing the total to 27..

We ~~continue to evaluate the potential of downspacing to 40-acre and 60-acre units, with the results~~continued our successful delineation of the ~~downspacing pilots expected to be released in December 2013. We also continue to evaluate the~~ Austin Chalk and Pearsall formations across our acreage position. To date, we have completed four Austin Chalk wells with average 24-hour initial production ("IP") rates of 980 gross barrels of oil equivalent per day (“boed”) (485 barrels per day ("bbld") of crude oil and condensate, 220 bbld of NGLs and 1.65 million cubic feet per day ("mmcfd") of natural gas). Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar toChalk/Upper Eagle Ford ~~condensate wells. Also in the second quarter of 2013, one Pearsall well was~~for co-development with an initial 15,500 net acres now delineated. Nine additional Austin Chalk/Upper Eagle Ford wells are currently being drilled, completed ~~with a 24-hour IP rate of 580 gross boed.~~or awaiting first production.

Bakken – Average net sales volumes from the Bakken shale were 3950 mboed and 3846 mboed in the second quarter and first six months of2014 ~~of 2013~~ compared to 2639 mboed and 38 mboed in the same periods of ~~2012.~~2013, for increases of 28 percent and 21 percent. Our Bakken production averages approximately 90 percent crude oil, 5four percent NGLs and 5six percent natural gas. During the second quarter of ~~2013~~2014, we reached total depth on 2219 gross operated wells and brought 1619 gross operated wells to ~~sales.~~sales compared to 22 reaching total depth and 16 brought to sales in the second quarter of 2013. During the first six months of ~~2013~~2014, we reached total depth on 4035 gross operated wells and brought 3830 gross operated wells to ~~sales.~~sales compared to 40 reaching total depth and 38 brought to sales in the same period of 2013. Our second quarter average time to drill a well ~~continued to improve, averaging 15~~was 17 days spud-to-total depth, compared to 15 days in the same period of 2013.

We recompleted eight wells during the second quarter of 2014, and ~~22 days spud-to-spud.~~a total of 13 wells in the first six months of 2014, in the Myrmidon and Hector areas. With our continued success in earlier 320-acre spacing pilots, four additional spacing pilots with six Middle Bakken and six Three Forks first bench wells are planned. The first of these new 12-well spacing pilots spud in July, with the remainder planned over the balance of 2014. During the second half of 2014, more than 50 percent of planned Bakken wells will test enhanced completion designs, including elevated proppant volumes, slickwater and hybrid fracs, increased stages and cemented liners.

Oklahoma ~~Resource Basins~~resource basins – Net sales volumes from the ~~Anadarko Woodford shale~~Oklahoma resource basins averaged 1318 mboed and 17 mboed in the second quarter and first six months of2014 ~~of 2013~~ compared to 613 mboed ~~and 5 mboed~~ in both of the same periods of ~~2012.~~2013, for increases of 38 percent and 31 percent. Our Oklahoma resource basins production averaged approximately 44 percent liquid hydrocarbons and 56 percent natural gas for the second quarter of 2014. During the second quarter of ~~2013~~2014, we reached total depth on ~~two~~six gross operated wells and ~~three~~brought four gross ~~operated~~SCOOP wells ~~were brought~~ to ~~sales, while during~~sales. During the first six months of ~~2013~~2014, we reached total depth on ~~two~~11 gross operated wells and brought ~~seven~~eight gross operated wells to sales.

We ~~anticipate drilling will begin on two~~continue to test other horizons in Oklahoma, with three operated wells ~~each~~producing in the Southern Mississippi ~~Lime formation in central Oklahoma~~Trend and ~~the~~a second operated Granite Wash ~~formation~~horizontal well brought online. Three additional operated wells in ~~northwestern Oklahoma during~~the Southern Mississippi Trend are scheduled to spud in the second half of ~~2013.~~2014. During the second quarter of 2014, we executed agreements to add approximately 30,000 net acres to our Oklahoma resource position, bringing our overall position to more than 300,000 net acres.

Wyoming – Operated production at the Powder River Basin field ceased in March 2014. Plug and abandonment activities are expected to be completed in the fall of 2014.

~~Exploration~~North America E&P--Exploration

Gulf of Mexico – ~~Late in the third quarter of 2013, we expect to begin drilling the first exploration~~A well on the Madagascar prospect located on De Soto Canyon Block 757. We reduced our working interest in the Madagascar prospect from 100 percent to 70 percent as a result of a farm-down in the second quarter of 2013 with no up-front cash proceeds. We anticipate further reducing our interest to a target of 40 to 50 percent working interest by the time of drilling.

~~We participated in an appraisal well on the Gunflint prospect located on Mississippi Canyon Block 992 in which we hold an 18 percent non-operated working interest.~~ The appraisal well successfully encountered 109 feet of net pay within the primary reservoir targets. After penetrating the initial appraisal targets, the well was deepened to a previously untested Lower Miocene interval. Commercial hydrocarbons were not encountered in the deeper exploration objective. Additional exploration potential

~~remains in an adjacent structure to the north, which is a candidate for future exploration following development of the confirmed resources.~~

~~The first appraisal well on the Shenandoah~~Key Largo prospect, located on Walker Ridge Block ~~51,~~578, is anticipated to spud in the third quarter of 2014 as the first well with a new-build deepwater drillship. We are operator and hold a 60 percent working interest in the prospect.

The second appraisal well on the non-operated Shenandoah prospect was spud in late May 2014 and is still drilling. The well is located on Walker Ridge Block 52, in which we ~~have~~hold a 10 percent working interest.

An exploration well is anticipated to spud in the second half of 2014 on the Perseus prospect, located on Desoto Canyon Block 231. We hold a 30 percent non-operated working interest ~~reached total depth~~ in the ~~first quarter of 2013. This appraisal well successfully encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs.~~prospect.

~~In March 2013, we submitted bids totaling $33 million for 100 percent working interest in two blocks in the Central Gulf of Mexico Lease Sale 227: Keathley Canyon Block 340 on the Colonial prospect~~North America E&P--Acquisitions and ~~Keathley Canyon Block 153, an extension~~Dispositions

See Note 5 to the ~~Meteor prospect on our existing Keathley Canyon 196 lease. Keathley Canyon Blocks 340 and 153 are both inboard-Paleogene prospects. These leases were awarded to us in the second quarter of 2013.~~consolidated financial statements for information about these dispositions.

Canada – During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 thousand barrels per day ("mbbld") steam assisted gravity drainage ("SAGD") demonstration project. We are expecting to receive regulatory approval for this project in early 2014. Upon receiving this approval, we will further evaluate our development plans.

International E&P&P--Production

~~Production~~

~~Net liquid hydrocarbon and~~



	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Net Sales Volumes
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	31	30	33	34
United Kingdom	13	14	13	17
Libya	—	45	—	39
Total Liquid Hydrocarbons	44	89	46	90
Natural Gas (mmcfd)
Equatorial Guinea	446	401	441	424
United Kingdom^(a)	28	36	29	38
Libya	—	24	1	25
Total Natural Gas	474	461	471	487
Equivalent Barrels (mboed)
Equatorial Guinea	105	97	107	105
United Kingdom^(a)	18	20	18	23
Libya	—	49	—	43
Total International E&P (mboed)	123	166	125	171
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,624	5,820	6,601	6,301
Methanol (mtd)	980	973	1,066	1,191


^(a)	Includes natural gas acquired for injection and subsequent resale of 5 mmcfd and 8 mmcfd for the second quarters of 2014 and 2013, and 6 mmcfd and 10 mmcfd for the first six months of 2014 and 2013.

International E&P segment average net sales volumes ~~averaged~~ ~~262~~ ~~mboed and~~ ~~268~~ ~~mboed during~~in the second quarter and first six months of2014 of ~~2013~~decreased 26 percent and 27 percent when compared to~~261~~ ~~mboed and~~ ~~249~~ ~~mboed in the same periods of~~ ~~2012, which is flat for the quarter and an increase of~~ ~~8 percent~~ ~~for the six-month period. During the first six months of~~ ~~2013~~, Libya net liquid hydrocarbon and natural gas sales volumes increased 5 mboed and 13 mboed, compared to the same periods of 2012, primarily due to limited resumption of sales in early 2012 after the 2011 civil unrest. In addition, both the second quarter and first six months of2013. We had lower oil sales from Libya in 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal. Excluding Libya, net sales volumes increased 5 percent in the second quarter of 2014 and decreased 2 percent in the first six months of 2014 compared to the same periods of 2013 ~~include~~. The second quarter 2014 net ~~liquid hydrocarbon~~ sales ~~volumes~~volume increase, excluding Libya, is due to increased sales from Equatorial Guinea due to a planned turnaround at the LNG facility during the second quarter of ~~9 mboed from~~2013. The net sales volume decrease for the ~~PSVM development located on~~first six months of 2014, excluding Libya, is primarily related to reliability issues at the ~~northeastern portion of Angola Block 31 which had first sales in February 2013.~~non-operated U.K. Foinaven field as well as natural production decline within the U.K. Brae fields.

Equatorial Guinea – Average net sales volumes were 97105 mboed and ~~105~~107 mboed in the second quarter and first six months of2014 compared to ~~101~~97 mboed and ~~103~~105 mboed in the same periods of ~~2012. The planned turnaround that occurred in April~~ 2013 ~~was safely completed in 22 days, eight days ahead of schedule and below budget. Sales~~. Second quarter 2014 net sales volumes are higher than in the ~~second~~same quarter of 2013 because sales volumes were impacted by a planned turnaround at the ~~turnaround, but operational availability of 98 percent~~LNG facility in April 2013. Net sales volumes for the first six months of 2014 are only slightly higher because first quarter ~~of 2013 bolstered~~2014 sales ~~for~~were impacted by scheduled offshore riser repairs, an unplanned repair at the ~~six-month period.~~methanol plant and a planned nine-day partial shut-down at the LNG facility.

~~Norway~~United Kingdom – ~~The production decline in the Alvheim area continues to be less than expected.~~ Average net sales volumes ~~from Norway~~ were 8818 mboed in both the second quarter and first six months of2014 ~~of 2013~~ compared to 8620 mboed and 9223 mboed in the same periods of 2012. These better-than-expected results have been achieved through continued strong operational performance that delivered availability of approximately 96 percent in the second quarter and 97 percent in the first quarter of 2013~~; production optimization from well management;~~, with decreases of 10 percent and ~~reservoir and well performance~~22 percent, primarily as a result of reliability issues at the ~~upper end of expectations primarily due~~non-operated Foinaven field as well as natural decline within the Brae fields and planned and unplanned maintenance activities that resulted in lower overall operating availability. Planned maintenance activities on the non-operated Forties Pipeline System is expected to ~~a delay~~impact Brae net sales volumes in ~~anticipated water breakthrough at the Volund field. A planned 10-day turnaround in Norway is scheduled during~~ the third quarter of ~~2013.~~2014.

~~United Kingdom~~Libya – ~~Production~~Libya's National Oil Corporation in early July 2014 rescinded force majeure associated with the third-party labor strikes at ~~non-operated Foinaven was shut-in in mid-July 2013 due to compression and subsea equipment issues and is expected~~the Es Sider oil terminal. However, liftings have yet to resume ~~at partial rates in mid-August. Planned pipeline curtailments~~ and ~~a turnaround at Brae in the North Sea in the second half of 2013 will also reduce third quarter 2013 production.~~there remains uncertainty around future production and sales levels.

~~Exploration~~

International E&P--Exploration

Kurdistan Region of Iraq – We hold 45 percent operated working interests in both the Harir and Safen blocks. Current exploratory drilling includes the Mirawa well which began in March 2013 on the Harir Block and the Safen well which commenced drilling in April 2013 on the Safen Block. The ~~Mirawa~~Jisik-1 exploration well reached total depth in ~~July~~June 2014 on the operated Harir Block. Testing is underway. Following the successful 2013 ~~and is currently testing. The Safen~~Mirawa-1 discovery, the Mirawa-2 appraisal well is expected to ~~reach projected total depth in August 2013, with testing programs to follow.~~

Additionally, following the successful appraisal program on the non-operated Atrush Block a declaration of commerciality was filed with the government in 2012, and a plan of development was filed in May 2013. The development plan is currently under review with final approval expectedspud in the third quarter of ~~2013.~~2014. We ~~anticipate first~~hold a 45 percent operated working interest in the Harir Block.

On the non-operated Sarsang Block, the East Swara Tika-1 exploratory well reached a total depth of approximately 13,000 feet in June 2014 and testing is underway. The co-venturers declared the Swara Tika discovery commercial in May 2014 and filed a field development plan in June. Testing of the Mangesh well was finalized and the well costs were charged to dry well expense in the second quarter of 2014. Due to a contract amendment in April 2014, we hold a 20 percent non-operated working interest in the Sarsang block.

The Chiya Khere-5 development well (formerly Atrush-5), included in the previously approved Atrush development plan, was spud in May 2014 and reached a total depth of approximately 6,900 feet in late June, ahead of schedule and under budget. The well will be tested in early 2015 prior to final completion and tie-in to the phase one production ~~in 2015.~~facility as part of the previously approved Atrush development plan. The ~~Atrush-3 appraisal~~Atrush-4 development well ~~has~~ reached total depth in January 2014. Well testing was completed in April and ~~is currently testing.~~the well has been suspended as a future producer. We hold a 15 percent non-operated working interest in the Atrush Block.

OnKenya – The Sala-1 exploration well was spud in February 2014 on the ~~non-operated Sarsang block, two exploration wells, the Mangesh~~eastern side of Block 9 and ~~the Gara, began drilling~~made a natural gas discovery in the second ~~half~~quarter of ~~2012~~2014. The well was drilled to a total depth of approximately 10,000 feet and ~~have~~analysis indicated three zones of interest over a 3,280-foot gross interval which were subsequently drill-stem tested. The Sala-2 appraisal well spud in the third quarter of 2014. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development.

Ethiopia – Two wells were drilled on the South Omo Block: the Shimela-1 well, which reached total depth ~~with testing programs ongoing. Also on~~in May 2014, and the ~~Sarsang block, the East Swara Tika exploration~~Gardim-1 well, ~~began drilling~~which reached total depth in July ~~2013~~2014. Neither well encountered commercial hydrocarbons and the well costs were charged to ~~test additional resource potential to the northeast of the previously announced Swara Tika discovery. We hold a 25 percent working interest~~dry well expense in the ~~Sarsang Block.~~

Ethiopia – The Sabisa-1 exploration well, on the onshore South Omo block in a frontier rift basin, encountered reservoir quality sands, oil and heavy gas shows and a thick shale section. The presencesecond quarter of oil prone source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified in the basin. Because of mechanical issues, the well was abandoned before a full evaluation could be completed. The rig will mobilize to the nearby Tultule prospect, approximately two miles from the Sabisa-1 during the second half of 2013.2014. We hold a 20 percent non-operated ~~working~~ interest in the South Omo ~~block.~~Block.

~~Gabon – Exploration drilling began~~Early in ~~April 2013 on~~2014, we increased our acreage in Ethiopia through a farm-in to the ~~Diaman well in the Diaba License G4-223, offshore Gabon, to test the deepwater presalt play. The well reached total depth in the third quarter of 2013. Logging and evaluation are underway.~~Rift Basin Area Block with 10.5 million gross acres. We hold a 2150 percent non-operated working interest in the ~~Diaba License.~~block with the option to operate if a discovery is made.

Gabon – In late October 2013, we were the high bidder as operator on the G13 deepwater block in the pre-salt play offshore Gabon. Negotiations toward a final production sharing contract are ongoing.

Poland – During the first quarter of 2014, we relinquished our remaining 4 operated concessions to the government.

International E&P--Acquisitions and Dispositions

In June 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, with an effective date of January 1, 2014. We ~~commenced drilling~~expect the transaction to close in the fourth quarter of 2014, pending government and regulatory approvals, with net proceeds of $2.1 billion.

The Norway business is excluded from the ~~Sverdrup exploration~~International E&P segment results and is reported as discontinued operations, average net sales volumes from Norway were 70 mboed in both the second quarter and first six months of2014 compared to 87 mboed and 88 mboed in the same periods of 2013. The decrease was primarily as the result of water breakthrough, as anticipated, at Volund, as well ~~on PL 330 offshore Norway~~as natural decline in ~~June 2013 and total depth is expected to be reached in early September 2013. We hold a 30 percent non-operated working interest in this license. The Darwin (formerly Veslemoy) exploration well~~the remaining fields. Alvheim was ~~drilled~~also impacted in the first quarter of ~~2013~~2014 by severe winter weather which resulted in eight days of curtailed production. Planned maintenance and system upgrades on ~~PL 531~~the Alvheim floating production, storage and offloading vessel are expected to impact production in ~~which~~the third quarter.

In the first quarter of 2014, we ~~hold a~~closed the sales of our non-operated 10 percent ~~non-operated fully-carried~~ working ~~interest. Gas shows were recorded~~interests in the ~~Paleocene objective section, although no hydrocarbons were found in~~Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. See Note 5 to the ~~Cretaceous section and the well has been plugged and abandoned.~~consolidated financial statements for information about these dispositions.

Poland – After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. We are evaluating disposition options for our concessions.

~~Kenya – The first exploratory well on Block 9 is expected to commence before the end of 2013 onshore Kenya where we hold a 50 percent non-operated working interest.~~

~~Angola – The Kaombo development, located in the southeastern portion of Block 32, is expected be sanctioned late in 2013 so that production from the Kaombo development is possible in 2017.~~

Oil Sands Mining

Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the ~~Athabasca Oil Sands Project (“AOSP”).~~AOSP. Our net synthetic crude oil sales volumes were 4344 mbbld and 4745 mbbld in the second quarter and first six months of of ~~2013~~2014 compared to 43 mbbld and 4447 mbbld in ~~each of~~ the same periods of ~~2012~~2013. ~~Sales were relatively flat~~The six-month period of 2014 was impacted by lower mine reliability and nine days of planned mine maintenance in ~~all periods with the exception of the first six months of 2013. The impact of strong reliability experienced at both mines and the upgrader during~~ the first quarter of ~~2013 was partially offset by unplanned mine downtime~~2014 and a planned turnaround ~~during~~in the second quarter of 2013.

~~Acquisitions and Dispositions~~

In June 2013, we entered into an agreement to sell our non-operated 10 percent working interest in the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, valued at $1.5 billion before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government, regulatory and third-party approvals.

~~In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.~~

~~In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.~~

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments made in the second quarter of 2013, the pretax gain on this sale was $55 million.

~~In January 2013, government approval was received for our acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia.~~

As previously disclosed, we had engaged in discussions with respect to a potential sale of a portion of our 20 percent outside-operated interest in the AOSP. An agreement was not reached with the prospective purchaser and negotiations have been terminated. We are not engaged in further discussions with respect to a potential sale of these assets.

We continue to progress the potential sale of assets in an ongoing effort to optimize our portfolio for profitable growth, with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have agreed upon or completed divestitures of approximately $2.9 billion.

The above discussions include forward-looking statements with respect to anticipated drilling activity, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, planned infrastructure improvements in the

2224

Eagle Ford operating area, additional farm-down of our working interest in the Madagascar prospect in the Gulf of Mexico, anticipated exploration activity in the Gulf of Mexico, the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and Kenya, the development of our in-situ assets, a planned turnaround in Norway, planned pipeline curtailments and turnaround at Brae in the North Sea, expected timing and rate of production returning at Foinaven, the timing of approval of a plan of development and first production for the Atrush Block, plans to exit Poland, the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, and the projected asset dispositions through 2013. The average times to drill a well and expectations as to future drilling times may not be indicative of future drilling times. The current production rates may not be indicative of future production rates. Factors that could potentially affect anticipated drilling activity, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, planned infrastructure improvements in the Eagle Ford operating area, anticipated exploratory activity in the Gulf of Mexico, the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and Kenya, a planned turnaround in Norway and planned pipeline curtailments and turnaround at Brae in the North Sea include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other associated risks with construction projects, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government, regulatory and third-party approvals. The expected timing and rate of production returning at Foinaven, additional farm-down of the our working interest in the Madagascar prospect in the Gulf of Mexico, plans to exit Poland, the timing of approval of a plan of development and first production for the Atrush Block and the projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future performance. The development of our in-situ assets is dependent on obtaining regulatory approval and future development plans. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Market Conditions

Prevailing prices for the ~~various qualities of~~ crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. ~~Worldwide prices have been volatile in recent years.~~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 ~~lists benchmark~~presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas ~~price averages relative to our North America E&P and International E&P segments in~~for the second quarter and first six months of of ~~2013~~2014 and ~~2012~~2013.

Three Months Ended June 30, Six Months Ended June 30,
Benchmark 2013 2012 2013 2012
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)

$94.17

$93.35
$94.26 $98.15
Brent (Europe) crude oil (Dollars per barrel)

$102.58

$108.42
$107.54 $113.45
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))^(a)

$4.09

$2.22
$3.71 $2.48



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl)
Bakken		$93.08		$88.65		$91.43		$89.89
Eagle Ford	99.08		99.40		97.65		101.50
Oklahoma resource basins	101.12		90.51		98.05		90.32
Other North America	93.45		91.32		91.40		89.31
Total Crude Oil and Condensate	95.95		93.75		94.30		94.20
Natural Gas Liquids (per bbl)
Bakken		$45.13		$35.92		$51.04		$38.42
Eagle Ford	30.20		28.09		33.76		28.12
Oklahoma resource basins	33.04		27.99		38.21		34.77
Other North America	54.13		51.05		57.65		53.71
Total Natural Gas Liquids	34.80		31.72		38.75		33.51
Total Liquid Hydrocarbons (per bbl) ^(b)
Bakken		$90.47		$85.96		$89.16		$87.23
Eagle Ford	85.36		83.90		84.78		85.88
Oklahoma resource basins	52.00		47.05		55.04		49.88
Other North America	90.45		88.64		88.97		87.02
Total Liquid Hydrocarbons	86.43		84.51		85.65		85.30
Natural Gas (per mcf)
Bakken		$4.12		$4.47		$6.14		$4.02
Eagle Ford	4.76		4.17		4.83		3.80
Oklahoma resource basins	4.57		4.71		5.01		4.13
Other North America	5.65		4.01		5.35		4.11
Total Natural Gas	5.00		4.19		5.14		4.02
Benchmarks
West Texas Intermediate ("WTI") crude oil (per bbl)		$102.99		$94.17	$100.84		$94.26
Louisiana Light Sweet ("LLS") crude oil (per bbl)^(c)	105.55		104.77		104.97		107.36
Mont Belvieu NGLs (per bbl)^(d)	34.54		31.84		36.42		32.84
Henry Hub natural gas^(e) (per mmbtu)^(f)	4.67		4.09		4.80		3.71


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


^(b)	Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations by $1.26 and $0.50 per bbl for the second quarter and first six months of 2013. There were no crude oil derivative instruments for the second quarter and first six months of 2014.


^(c)	Bloomberg Finance LLP: LLS St. James.


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


^(e)	Settlement date average.

~~North America E&P~~


^(f)	Million British thermal units.

~~Liquid hydrocarbons~~Crude oil and condensate – The quality ~~location~~ and ~~composition~~location of our ~~liquid hydrocarbon~~ production mix can cause our ~~U.S. liquid hydrocarbon~~North America E&P price realizations to differ from the WTI benchmark.

Quality – Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and ~~produces~~has historically produced higher value products; therefore, light sweet crude is considered of higher quality and ~~typically sells~~has historically sold at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude oil and condensate production that is classified as light sweet crude has been ~~increasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines.~~increasing. In the second quarter and first six months of of ~~2013~~2014, the

percentage of our U.S. crude oil and condensate production that was sweet averaged 81 percent and 80 percent compared to 75 percent and 74 ~~percent compared to 42 percent and 45~~ percent in the same periods of ~~2012~~2013.

Location – ~~In recent years, crude~~Crude oil sold along the ~~United States~~U.S. Gulf Coast, such as that from the Eagle Ford, ~~shale,~~ has been priced based on the ~~Louisiana Light Sweet~~LLS benchmark which, ~~prices~~in recent years, has been at a premium to WTI, ~~and tracks closest to Brent,~~ while production from inland areas farther from large refineries has been atpriced lower. As a ~~discount~~result of significant increases in U.S. production of light sweet crude oil, the historical relationship between WTI and LLS pricing may not be indicative of future periods.

Natural gas liquids – Our net NGL sales volumes continue to ~~WTI.~~

~~Composition – The proportion~~grow due to development of our ~~liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were~~ 14U.S. resource plays, increasing by 23 percent ~~of our North America E&P liquid hydrocarbon sales volumes in~~ and 29 percent during the second quarter and first six months of of ~~2013~~2014 compared to~~9 percent~~ in the same periods of ~~2012~~2013. The majority of our NGL volumes are sold at reference to Mont Belvieu prices and our 2014 average price realizations reflect the increases in this benchmark.

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. Average Henry Hub settlement prices for natural gas were 8414 percent and 5029 percent higher for the second quarter and first six months of2014 than in the same periods of 2013 ~~compared to the same periods of the prior year.~~.

International E&P

The following table presents our average price realizations and the related benchmark for crude oil for the second quarter and first six months of2014 and 2013.



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014	2013
Average Price Realizations ^(a)
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea	$59.72		$54.09		$61.12	$60.58
United Kingdom	110.51		101.85		110.02	108.01
Libya	—		117.55		—	122.64
Total Liquid Hydrocarbons	75.41		93.62		75.48	96.65
Natural Gas (per mcf)
Equatorial Guinea^(b)	$0.24		$0.24		$0.24	$0.24
United Kingdom	8.04		10.23		9.07	10.78
Libya	—		4.65		5.45	4.86
Total Natural Gas	0.69		1.24		0.80	1.31
Benchmark
Brent (Europe) crude oil (per bbl)		$109.70		$102.58	$108.93	$107.54

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


^(b)	Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment.

Liquid hydrocarbons – Our ~~international crude oil~~U.K. liquid hydrocarbon production is relatively sweet and is generally sold in relation to the Brent crude ~~benchmark, which was 5 percent~~benchmark. Our liquid hydrocarbon production from Equatorial Guinea includes condensate and NGLs that receive lower ~~in both the~~ ~~second quarter and first six months~~ of ~~2013~~prices than ~~the same periods of~~ ~~2012~~.crude oil.

Natural gas – Our major international natural gas-producing regions are ~~Europe~~the U.K. and Equatorial Guinea. Natural gas prices in Europe have been considerably higher than in the U.S. in recent years. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices ~~may~~will not fully track market price movements.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational ~~problems~~reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix ~~will track~~have historically tracked movements in WTI and one-third ~~will track~~have historically tracked movements in the Canadian heavy ~~sour~~ crude oil marker, primarily Western Canadian Select ("WCS"). ~~A decrease~~Comparing the same periods of 2014 and 2013, the WCS discount to WTI widened in the ~~WTI benchmark prices, coupled with a higher WCS discount from WTI~~second quarter, increasing $0.93 per barrel; however, in the first six months, of ~~2013~~ ~~compared to same period of~~ ~~2012, created downward pressure on our average realizations. However, in the second quarter of 2013 compared to the second quarter of 2012,~~ the WCS discount ~~from~~to WTI ~~has~~ narrowed ~~with the discount remaining at these lower levels into July 2013.~~by $3.93 per barrel.

The operating cost structure of ~~the~~our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil ~~prices, respectively.~~prices.

The following table ~~below shows benchmark prices~~presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for the second quarter and first six months of of ~~2013~~2014 and ~~2012~~2013:.

Three Months Ended June 30, Six Months Ended June 30,
Benchmark 2013 2012 2013 2012
WTI crude oil (Dollars per barrel)

$94.17

$93.35
$94.26 $98.15
WCS crude oil (Dollars per barrel)^(a)

$75.06

$70.63
$68.74
$76.07
AECO natural gas sales index (Dollars per mmbtu)^(b)

$3.45

$1.84
$3.31
$2.04



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014	2013
Average Price Realizations ^(a)
Synthetic Crude Oil (per bbl)	$94.17		$89.39		$91.27	$84.31
Benchmark
WTI crude oil (per bbl)		$102.99		$94.17	$100.84	$94.26
WCS crude oil (per bbl)^(b)		$82.95		$75.06	$79.25		$68.74
AECO natural gas sales index (per mmbtu)^(c)		$4.46		$3.45	$4.72		$3.31


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


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


^(b)(c)	Monthly average AECO day ahead index.

Results of Operations

Consolidated Results of Operation

~~Consolidated income before income taxes in the~~ ~~second quarter and first six months~~ of ~~2013~~ ~~was approximately 6 percent higher than in the same periods of~~ ~~2012~~ ~~primarily related to increases in sales volumes. The effective tax rate was~~ ~~72 percent~~ ~~in the~~ ~~first six months~~ of ~~2013~~ ~~compared to~~ ~~71 percent~~ ~~in the~~ ~~first six months~~ of ~~2012, with the increase related to higher income from operations in higher tax jurisdictions, primarily Libya.~~

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2013		2012		2013		2012		2014		2013		2014		2013
Sales and other operating revenues, including related party:
Sales and other operating revenues, including related party									Sales and other operating revenues, including related party
North America E&P	$	1,284	$	833	$	2,499	$	1,745	$	1,540	$	1,284	$	2,932	$	2,499
International E&P	1,732		1,813		3,619		3,476		347		826		727		1,721
Oil Sands Mining	353		329		741		698		383		353		760		741
Segment sales and other operating revenues, including related party	$	3,369	$	2,975	$	6,859	$	5,919	$	2,270	$	2,463	$	4,419	$	4,961
Unrealized gain (loss) on crude oil derivative instruments	50		—		—		—
Total sales and other operating revenues, including related party	$	3,419	$	2,975	$	6,859	$	5,919
Unrealized gain on crude oil derivative instruments									—		50		—		—
Sales and other operating revenues, including related party									$	2,270	$	2,513	$	4,419	$	4,961

~~Total~~North America E&P sales and other operating revenuesincreased ~~$444 million~~20 percent and ~~$940 million~~17 percent in the second quarter and first six months of2014 of from the comparable prior-year periods primarily due to higher liquid hydrocarbon net sales volumes from continued growth across our three U.S. resource plays, combined with higher average price realizations for all products.

The following tables display changes in North America E&P segment sales and other operating revenues by product. 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)	June 30, 2013		Price Realizations			Net Sales Volumes			June 30, 2014
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	1,144	$	31		$	228		$	1,403
Natural gas	120		22			(9		)	133
Realized gain on crude oil
derivative instruments	17		(17		)				—
Other sales	3								4
Total	$	1,284							$	1,540



	Six Months Ended		Increase (Decrease) Related to						Six Months Ended
(In millions)	June 30, 2013		Price Realizations			Net Sales Volumes			June 30, 2014
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	2,239	$	11		$	397		$	2,647
Natural gas	239		60			(23		)	276
Realized gain on crude oil
derivative instruments	13		(13		)				—
Other sales	8								9
Total	$	2,499							$	2,932

International E&P sales and other operating revenues~~2013~~ decreased 58 percent in both the second quarter and first six months of 2014 from the comparable prior-year periods. The ~~$451 million and $754 million increases in the North America E&P segment in the second quarter and first six months of 2013~~decreases were primarily due to lower liquid hydrocarbon net sales volumes, ~~which increased~~ ~~59 percent~~ ~~over the same periods of~~ ~~2012~~, primarily ~~due to ongoing development programs~~ in ~~the Eagle Ford~~Libya as previously discussed, combined with lower average price realizations for both liquid hydrocarbons and ~~Bakken shale resources plays.~~natural gas.

The following ~~table gives details of~~tables display changes in International E&P segment sales and other operating revenues by product. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and ~~average realizations of our North America E&P segment.~~price realizations.

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld) ^(a)
148
93
145
91
Liquid hydrocarbon average realizations (per bbl) ^{(b) (c)}
$84.51 $84.72 $85.30 $89.23
Net crude oil and condensate sales volumes (mbbld)
126
85
124
83
     Crude oil and condensate average realizations (per bbl) ^(b)
$93.75 $89.04 $94.20 $93.25
     Net natural gas liquids sales volumes (mbbld)
22
8
21
8
     Natural gas liquids average realizations (per bbl) ^(b)
$31.72 $40.54 $33.51 $45.65

Net natural gas sales volumes (mmcfd)
316
319
328
331
Natural gas average realizations (per mcf)^(b)
$4.19 $3.42 $4.02 $3.79



	Three Months Ended		Increase (Decrease) Related to							Three Months Ended
(In millions)	June 30, 2013		Price Realizations			Net Sales Volumes				June 30, 2014
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	761	$	(73	)	$	(383	)	^(a)	$	305
Natural gas	52		(24		)	2				30
Other sales	13									12
Total	$	826								$	347


^(a)	Includes ~~crude oil, condensate and natural gas liquids.~~a $480 million decrease related to Libya.



	Six Months Ended		Increase (Decrease) Related to							Six Months Ended
(In millions)	June 30, 2013		Price Realizations			Net Sales Volumes				June 30, 2014
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	1,580	$	(178	)	$	(768	)	^(b)	$	634
Natural gas	116		(43		)	(4		)		69
Other sales	25									24
Total	$	1,721								$	727


^(b)	~~Excludes gains and losses on derivative instruments~~

^(c)

~~Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average liquid hydrocarbon realizations by~~ ~~$1.22~~ ~~per bbl and~~ ~~$0.45~~ ~~per bbl for the~~ ~~second quarter and first six months~~ of ~~2013. There were no realized gains (losses) on crude oil derivative instruments in the~~ ~~second quarter and first six months~~ of ~~2012~~.

Includes an $871 million decrease related to Libya.

As compared to prior year periods, International E&P sales and other operating revenues decreased $81 million in the second quarter of 2013 due to lower liquid hydrocarbon realizations and increased $143 million in the first six months of 2013 as a result of increased liquid hydrocarbon and natural gas sales volumes, partially offset by lower liquid hydrocarbon realizations.

2528

~~The following table gives details of net sales volumes and average realizations of our International E&P segment.~~

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
International E&P Operating Statistics
     Net liquid hydrocarbon sales volumes (mbbld)^(a)

Europe 93
99
96
98
Africa 84
78
82
65
Total International E&P 177
177
178
163
     Liquid hydrocarbon average realizations (per bbl)^(b)

Europe $106.41 $111.12 $111.43 $117.37
Africa $92.92 $96.84 $94.96 $95.87
Total International E&P $100.00 $104.82 $103.86 $108.80

Net natural gas sales volumes (mmcfd)

Europe^(c)
89
102
92
103
Africa 425
399
449
409
Total International E&P 514
501
541
512
     Natural gas average realizations (per mcf)^(b)

Europe $11.37 $10.05 $12.12 $10.02
Africa $0.49 $0.25 $0.50 $0.25
Total International E&P $2.37 $2.25 $2.47 $2.22


^(a)	Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.


^(b)	~~Excludes gains and losses on derivative instruments.~~


^(c)	~~Includes natural gas acquired for injection and subsequent resale of~~ 8 ~~mmcfd and~~ 17 ~~mmcfd for the~~ ~~second quarters of~~ ~~2013~~ ~~and~~ ~~2012, and~~ 10 ~~mmcfd and~~ 15 ~~mmcfd for the~~ ~~first six months~~ of ~~2013~~ ~~and~~ ~~2012~~.

Oil Sands Mining sales and other operating revenues increased ~~$24 million~~8 percent and ~~$43 million~~3 percent in the second quarter and first six months of of ~~2013~~2014 from the comparable prior-year periods. ~~Synthetic crude oil sales volumes were slightly lower~~The increase in the second quarter of ~~2013~~ ~~than~~2014 is primarily due to higher price realizations and increased net sales volumes as a result of a planned turnaround in the second ~~quarter of 2012; however, a decrease in the discount of WCS to WTI in~~ ~~second quarter of 2013~~ ~~resulted in increases in average realizations compared to the prior-year period. Synthetic crude oil sales volumes for the~~ ~~first six months~~ of ~~2013~~ ~~were 7 percent higher than in the~~ ~~first six months~~ of ~~2012, reflecting increased reliability of the mines and upgrader in the first~~ quarter of 2013. The increase in the first six months of 2014 is primarily due to higher price realizations, partially offset by lower net sales volumes, as previously discussed.

The following ~~table gives details of~~tables display changes in OSM segment sales and other operating revenues by product. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average ~~realizations of our Oil Sands Mining segment.~~price realizations.

Three Months Ended June 30, Six Months Ended June 30,
2013 2012 2013 2012
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld) ^(a)
43
44
47
44
Synthetic crude oil average realizations (per bbl)
$89.39 $79.31 $84.31 $85.07



	Three Months Ended		Increase (Decrease) Related to				Three Months Ended
(In millions)	June 30, 2013		Price Realizations		Net Sales Volumes		June 30, 2014
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	348	$	20	$	9	$	377
Other sales	5						6
Total	$	353					$	383

^(a)



	Six Months Ended		Increase (Decrease) Related to					Six Months Ended
(In millions)	June 30, 2013		Price Realizations		Net Sales Volumes			June 30, 2014
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	714	$	58	$	(22	)	$	750
Other sales	27							10
Total	$	741						$	760

~~Includes blendstocks.~~

Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the second quarter of 2013,, the net unrealized gain on crude oil derivative instruments was ~~$50~~$50 million while unrealized gains and losses did not have a significant impact on the first six months of 2013. There ~~was~~were no ~~comparable~~ crude oil derivative ~~activity in the same periods of 2012. See Note~~ 13 ~~to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.~~

~~Marketing revenues~~ ~~decreased~~ ~~$258 million~~ ~~and~~ ~~$677 million~~instruments in the second quarter and first six months of of 2014.

Marketing revenues~~2013~~ increased $121 million and $230 million in the second quarter and first six months of2014 from the comparable prior-year ~~periods.~~periods, related primarily to North America E&P segment marketing activities, ~~formerly referred to as supply optimization activities,~~ which ~~include the purchase of commodities from third parties for resale, have been decreasing in 2013 due to market dynamics. These activities~~ serve to aggregate volumes in order to satisfy transportation commitments ~~and~~as well as to achieve flexibility within product types and delivery points. The volume of activity was higher due to market dynamics and higher prices for crude oil and natural gas in both periods.

Income from equity method investmentsincreased ~~$17~~$43 million and ~~$57~~$62 million in the second quarter and first six months of of ~~2013~~2014 from the comparable prior-year periods primarily due to higher LNG average price realizations and net sales ~~volumes.~~ volumes due to a turnaround in the second quarter of 2013.

Net gain (loss) on disposal of assetsin the second quarter and first six months of ~~2013~~2014 primarily includes ~~a $114 million~~the loss on the sale of ~~our interests~~non-core acreage located in the ~~DJ Basin. In addition, the~~ ~~first six months~~ of ~~2013~~ include a $98 million gain on the sale of our interest in the Neptune gas plant, a $55 million gain on the sale of our remaining assets in Alaska and a $43 million loss on the conveyance of our interests in the Marcellus natural gas shale play to the operator. The net loss on disposal of assets in the ~~second quarter~~ of ~~2012~~ ~~reflects $36 million to settle all obligations as a result~~far northwest portion of the ~~assignment of exploration licenses in Indonesia. The net gain on disposal of assets in the~~ ~~first six months~~ of ~~2012~~ ~~consists primarily of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems, and the second quarter Indonesia loss.~~Williston Basin. See Note 5 to the consolidated financial statements for ~~information about these~~further details on dispositions.

Production expensesincreased$10 million in the second quarter of 2014 from the same quarter in 2013. North America E&P segment production expenses increased $22 million primarily related to higher net sales volumes in the U.S. resource plays. International E&P segment production expenses increased $16 million and included $5 million related to a turnaround at Brae in the U.K. during the second quarter of 2014. Lower sales volumes from Libya, rather than cost increases, contributed to the higher production expense rate (expense per barrel of oil equivalent or "boe") for the International E&P segment. OSM segment production expenses decreased $28 million in the second quarter of 2014, primarily because the year-ago quarter included higher costs associated with the planned turnaround.

In the first six months of 2014, production expenses increased $19 million compared to the same period of 2013. North America E&P segment production expenses increased $49 million primarily related to higher net sales volumes in the U.S. resource plays. International E&P segment production expenses increased $38 million due primarily to the discussed above and an $11 million charge for non-recurring riser repairs in Equatorial Guinea during the first quarter of 2014. Lower sales volumes from Libya, as discussed above, contributed to the higher production expense rate for the International E&P segment. OSM segment production expenses decreased $68 million in the first six months of 2014 due to the 2013 turnaround discussed above and lower contract services and contract labor costs in 2014.

The following table provides production expense rates for each segment:



	Three Months Ended June 30,				Six Months Ended June 30,
($ per boe)	2014		2013		2014		2013
Production Expense Rate
North America E&P		$10.47		$10.62		$10.74		$10.49
International E&P		$8.87		$5.43		$8.82		$5.19
Oil Sands Mining ^(a)	$51.53		$57.62		$49.54			$51.52


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

Marketing costsincreased $~~129~~120 million and ~~$205~~$229 million in the second quarter and first six months of of ~~2013~~2014 from the comparable prior-year periods, of ~~2012. The increases are primarily related to increased sales volumes in the North America E&P and International E&P segments and a planned turnaround in the OSM segment during the second quarter of 2013.~~

~~Marketing expenses~~ ~~decreased~~ ~~$260 million~~ ~~and~~ ~~$685 million~~ ~~in the~~ ~~second quarter and first six months~~ of ~~2013~~ ~~from the same periods of~~ ~~2012~~, consistent with the marketing ~~revenue decline~~revenues changes discussed above.

Exploration expenses were $364 million lower in the ~~second quarter~~first six months of ~~2013~~2014 than in the ~~same quarter in 2012 due to lower dry well costs and geological and geophysical costs. Exploration costs were higher in the~~ ~~first six months~~ of ~~2013~~ ~~than in the same period of~~ ~~2012, primarily due to larger unproved property impairments.~~comparable prior-year period. The first quarter of 2013 included $340 million in non-cash unproved property impairments on Eagle Ford ~~shale~~ leases that either ~~have~~ expired or that we dodid not expect to drill or extend. The following table summarizes the components of exploration ~~expenses.~~expenses:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2013		2012		2013		2012		2014		2013		2014		2013
Exploration Expenses									Exploration Expenses
Unproved property impairments	$	40	$	35	$	423	$	70	$	60	$	40	$	101	$	423
Dry well costs	50		81		71		104		53		50		55		71
Geological and geophysical	12		29		39		74		6		9		17		36
Other	31		27		65		59		26		26		45		52
Total exploration expenses	$	133	$	172	$	598	$	307	$	145	$	125	$	218	$	582

Depreciation, depletion and amortization(“DD&A”) increased $~~158~~54 million and ~~$331~~$66 million in the second quarter and first six months of of ~~2013~~2014 from the comparable prior-year periods. Our segments apply the units-of-production method to the majority of their ~~assets;~~assets, including capitalized asset retirement costs; therefore, ~~the previously discussed increases in sales~~ volumes ~~generally result in similar changes in~~have an impact on DD~~&A.~~&A expense. The DD&A rate (expense per ~~barrel of oil equivalent)~~boe), which is impacted by changes in reserves and capitalized costs, can also cause changes into our DD&A. ~~An increase in the North America E&P~~

Increased DD&A ~~rate~~ in the second quarter and first six months of2014 primarily reflects the impact of ~~2013~~ ~~compared to the same prior-year periods was primarily due to the ongoing development programs in the Eagle Ford and Bakken shale resources plays. A~~higher North America E&P net sales volumes from our three U.S. resource plays; partially offset by lower International E&P segment sales volumes from Libya as previously discussed.

The International E&P segment DD&A rate increased in the second quarter and first six months of ~~2013~~,2014 primarily due to ~~reserve increases~~increased amortization of capitalized asset retirement costs due to revisions to estimates of abandonment obligations in the U.K. at the end of ~~2012~~ ~~and in~~ the second quarter of ~~2013~~ ~~for Norway, compared to the same periods in~~ ~~2012~~ ~~partially offset the impact of the higher North America E&P rate and higher sales volumes.~~2013. The following table provides DD&A rates for each ~~segment.~~segment:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
($ per boe)	2013		2012		2013		2012		2014		2013		2014		2013
DD&A rate
DD&A Rate
North America E&P		$27		$22		$27		$23		$26.58		$26.74		$26.72		$26.78
International E&P		$8		$10		$8		$9		$6.64		$5.15		$6.45		$5.41
Oil Sands Mining		$12		$13		$12		$13		$11.78		$12.25		$11.74		$12.19

Impairmentsare discussed in ~~the~~ ~~first six months~~ of ~~2013~~ ~~related to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the~~ ~~first six months~~ of ~~2012~~ ~~were also related to the Ozona development in the Gulf of Mexico. See~~ Note 12 to the consolidated financial ~~statements for information about these impairments.~~statements.

Taxes other than income include production, severance and ad valorem taxes, primarily in the United States, which tend to increase or decrease in relation to sales volumes and ~~revenues.~~

~~General~~revenue. With the increase in North America E&P revenues and ~~administrative expenses~~ net sales volumes, taxes other than income increased ~~$10~~$16 million and ~~$25 million in the second quarter and first six months of 2013 from the comparable prior year periods primarily due to pension settlement charges of $17 million in the second quarter of 2013.~~

~~Net interest and otherincreased~~ $~~14 million~~ ~~and~~ ~~$36~~29 million in the second quarter and first six months of of ~~2013~~2014 from the comparable ~~periods~~prior-year periods. The following table summarizes the components of taxes other than income:



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2014		2013		2014		2013
Production and severance	$	68	$	54	$	122	$	101
Ad valorem	19		19		38		36
Other	22		20		44		38
Total	$	109	$	93	$	204	$	175

General and administrative expensesdecreased$20 million~~2012~~ in the second quarter of 2014 compared to the same period in 2013 primarily due to a lower ~~capitalized~~pension settlement charge as well as lower employee related costs. Partial settlements of our U.S. pension plans resulted in charges of $8 million and $17 million in the second quarters of 2014 and 2013. The increase in the first six months of 2014 from the comparable prior-year period was $4 million due to higher pension settlements in 2014, nearly offset by lower employee related costs and less contract services. Partial settlements of our U.S. pension plans resulted in charges of $71 million and $17 million in the first six months of 2014 and 2013.

Net interest and other decreased $15 million in ~~2013.~~the first six months of 2014 compared to the same period in 2013 primarily due to a dividend received in the first quarter of 2014 from a mutual insurance company of which we are an owner.

Provision for income taxes ~~increased $53 million and~~ decreased$~~151~~412 million ~~in the~~ ~~second quarter~~and ~~first six months of~~ ~~2013~~ ~~from the comparable periods of~~ ~~2012~~ ~~primarily due to the increase in pretax income.~~

The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to items not allocated to segments is shown in corporate and other unallocated items in the segment income table below.

~~Our effective tax rates in the~~ ~~first six months of 2013~~ ~~and~~ ~~2012~~ ~~were~~ ~~72 percent~~ ~~and~~ ~~71 percent~~. These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate. In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels. Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the ~~first six months of 2013~~ ~~and~~ ~~2012~~, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the periods. Excluding Libya, the effective tax rates would be 63 percent and 64 percent for the ~~first six months of 2013~~ ~~and~~ ~~2012~~.

~~Segment Income~~

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2013 2012 2013 2012
North America E&P $ 221
$ 70
$ 162
$ 174
International E&P 382
373
835
780
Oil Sands Mining 20
50
58
88
Segment income 623
493
1,055
1,042
Items not allocated to segments, net of income taxes:

Corporate and other unallocated items (156 ) (77 ) (227 ) (148 )
Unrealized gain (loss) on crude oil derivative instruments 32
—
—
—
Net gain (loss) on dispositions (73 ) (23 ) (9 ) 83
Impairments —
—
(10 ) (167 )
Net income $ 426
$ 393
$ 809
$ 810

~~North America E&P segment incomeincreased $151 million in the~~ ~~second quarter of 2013~~ ~~and decreased $12 million in the~~ ~~first six months of 2013~~ ~~compared to the same periods of~~ ~~2012. The increase in the second quarter of 2013 is largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford and Bakken shale resource plays. The decrease in the~~ ~~first six months of 2013~~ ~~was primarily the result of unproved property impairments, higher DD&A and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon net sales volumes, as discussed above.~~

~~International E&P segment incomeincreased $9 million and $55~~$662 million in the second quarter and first six months of2014 from the comparable prior-year periods primarily as a result of ~~2013~~ ~~compared~~reduced pretax income in Libya. See Note 8 to the ~~same periods~~consolidated financial statements for discussion of the effective tax rate.

Discontinued operations~~2012~~ are presented net of tax. See the preceding Operations section and Note ~~. These increases were primarily related~~5 to ~~higher liquid hydrocarbon net sales volumes and increased~~the consolidated financial statements for financial information about discontinued operations.

Segment Income

Segment income represents income from ~~equity method investments, partially offset by higher~~continuing operations excluding certain items not allocated to segments, net of income ~~taxes.~~taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on dispositions or other items that affect comparability also are not allocated to operating segments.

The following table reconciles segment income to net income:



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2014			2013			2014			2013
North America E&P	$	302		$	221		$	544		$	162
International E&P	160			170			381			443
Oil Sands Mining	55			20			119			58
Segment income	517			411			1,044			663
Items not allocated to segments, net of income taxes	(157		)	(170		)	(286		)	(264		)
Income from continuing operations	360			241			758			399
Discontinued operations ^(a)	180			185			931			410
Net income	$	540		$	426		$	1,689		$	809


^(a)	We sold our Angola assets in the first quarter of 2014 and entered into an agreement to sell our Norway business in June 2014. The Angola and Norway businesses are reflected as discontinued operations in all periods presented.

~~Oil Sands Mining~~North America E&P segment income ~~decreased $30~~increased $81 million and $382 million after-tax in the second quarter and first six months of of ~~2013~~2014 compared to the same periods of ~~2012. These decreases~~2013. The increases in both periods are primarily due to higher liquid hydrocarbon net sales volumes from the U.S. resource plays and higher price realizations, partially offset by higher production expenses ~~including~~and DD&A associated with the ~~costs~~higher volumes. In addition, the six-month period of 2013 included the previously discussed non-cash unproved property impairments.

International E&P segment incomedecreased $10 million and $62 million after-tax in the second quarter and first six months of2014 compared to the same periods of 2013. The decreases in both periods are primarily a result of the ~~scheduled upgrader~~previously discussed lower net sales volumes in Libya and lower price realizations, partially offset by reduced taxes associated with the lower sales volumes. In addition, the second quarter of 2014 had higher exploration expenses due to dry wells, partially offset by higher earnings from our equity method LNG operations in Equatorial Guinea due to a turnaround in the second quarter of 2013.

Oil Sands Mining segment incomeincreased $35 million and $61 million after-tax in the second quarter and first six months of2014 from the comparable prior-year periods. The second quarter 2014 increase was primarily due to higher price realizations and lower production costs associated with a planned turnaround in the second quarter of 2013. The increase in the first six months

2831

of 2014 was primarily the result of higher price realizations and lower production costs partially offset by lower net sales volumes due to lower mine reliability and the planned 2013 turnaround as previously discussed.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, ~~2012~~2013.

Accounting Standards Not Yet Adopted

~~In June 2013,~~See Note 2 to the Financial Accounting Standards Board ("FASB") ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. We do not expect this accounting standards update to have a significant impact on our consolidated ~~results of operations,~~ financial ~~position or cash flows.~~

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.statements.

Cash Flows and Liquidity

Cash Flows

~~Net~~The following table presents sources and uses of cash ~~provided by operating activitieswas~~ ~~$2,396 million~~and cash equivalents for the six months ended June 30, 2014 and 2013:



	Six Months Ended June 30,
(In millions)	2014			2013
Sources of cash and cash equivalents
Continuing operations	$	2,118		$	1,922
Discontinued operations	440			474
Disposals of assets	2,232			333
Other	113			98
Total sources of cash and cash equivalents	$	4,903		$	2,827
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(2,230	)	$	(2,405	)
Investing activities of discontinued operations	(233		)	(271		)
Purchases of common stock	(1,000		)	—
Commercial paper, net	(135		)	(200		)
Debt repayments	(34		)	(148		)
Dividends paid	(260		)	(241		)
Other	(10		)	—
Cash held for sale	(96		)	—
Total uses of cash and cash equivalents	$	(3,998	)	$	(3,265	)

Disposals of assets in the first six months of 2014 primarily reflect the net proceeds from the sales of our interests in Angola Blocks 31 and 32. In the first six months of 2013,~~, compared to~~ ~~$1,742 million~~ ~~in the~~ ~~first six months of 2012, primarily reflecting the impact of increased liquid hydrocarbon, natural gas and synthetic crude oil sales volumes on operating income.~~

~~Net cash~~ ~~used in~~ ~~investing activitiestotaled~~ ~~$2,299 million~~ ~~in the~~ ~~first six months of 2013, compared to~~ ~~$2,001 million~~ ~~in the~~ ~~first six months of 2012~~. Significant investing activities are additions to property, plant and equipment and disposal of assets. Additions in both periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. Disposals of assets totaled ~~$333 million~~ ~~and~~ ~~$218 million~~ in ~~first six months of 2013~~ ~~and~~ ~~2012, with 2013~~ net proceeds were primarily related to the sales of our Alaska assets and our interests in ~~our Alaska assets,~~ the Neptune gas plant and the DJ Basin. ~~In 2012, net proceeds resulted primarily from the sale of~~

Additions to property, plant and equipment are our ~~interests in several Gulf of Mexico crude oil pipeline systems.~~

~~For further information regarding capital expenditures by segment, see Supplemental Statistics.~~

~~Net cash~~ ~~used in~~ ~~financing activitieswas~~ ~~$543 million~~ ~~in the~~ ~~first six months of 2013, compared to~~ ~~$210 million~~ ~~provided by financing activities in the~~ ~~first six months of 2012. Repayments of debt at maturity were~~ ~~$148 million~~ ~~in the~~ ~~first six months of 2013~~ ~~and~~ ~~$111 million~~ ~~in the~~ ~~first six months of 2012. We also repaid a net $200 million of our outstanding commercial paper during the~~ ~~first six months of 2013~~ ~~compared to the same period in 2012, when we drew a net $550 million of commercial paper. Dividends paid of approximately~~ ~~$241 million~~ ~~were a~~most significant use of cash and cash equivalents. The following table breaks-out capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in ~~both periods.~~the consolidated statements of cash flows for the six months ended June 30, 2014 and 2013:



	Six Months Ended June 30,
(In millions)	2014			2013
North America E&P	$	1,969		$	1,874
International E&P	220			194
Oil Sands Mining	123			143
Corporate	13			40
Total capital expenditures	2,325			2,251
Change in capital expenditure accrual	(95		)	154
Additions to property, plant and equipment	$	2,230		$	2,405

Purchases of common stock are discussed in Note 17 to the consolidated financial statements.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. 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 short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

Credit Arrangements and Borrowings

In May 2014, we amended our $2.5 billion unsecured revolving credit facility which now matures in May 2019. See Note 15 to the consolidated financial statements for additional terms and rates. At June 30, ~~2013~~2014, we had no borrowings against our revolving credit facility orand no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility. ~~During the~~ ~~first six months of 2013~~, ~~$2,075 million~~ ~~of commercial paper was issued and~~ ~~$2,275 million~~ ~~of commercial paper was repaid.~~

At June 30, ~~2013~~2014, we had ~~$6,496~~$6,430 million in long-term debt outstanding, ~~$68~~$68 million of which is due within one year. 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.

The sale of our non-operated 10 percent working interest in Block 31 offshore Angola, a transaction valued at $1.5 billion before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government, regulatory and third-party approvals. We expect to use the proceeds from this sale principally to repurchase shares, but also to strengthen our balance sheet and for general corporate purposes.

Shelf Registration

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

Pending Asset Disposal

In June 2014, we entered into an agreement to sell our Norway business in a transaction expected to close in the ~~first~~fourth quarter of ~~2013, we changed our reportable segments~~2014. The $2.1 billion of proceeds will be prioritized first toward organic growth, with the balance available for share repurchases and ~~expect~~general corporate purposes. See Note 5 to ~~recast all periods presented to reflect these new segments in our~~the consolidated financial statements ~~no later than upon filing our 2013 Annual Report on Form 10-K with~~for additional discussion of the ~~SEC. When appropriate, we will update and file our universal shelf registration statement.~~Norway disposal.

Cash-Adjusted Debt-To-Capital Ratio

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total ~~debt-plus-equity-minus-cash)~~debt-plus-equity-minus-cash and cash equivalents) was21 percent at June 30, 2014, compared to 25 percent at ~~June 30, 2013~~ ~~and~~ December 31, ~~2012~~2013.


	June 30,			December 31,			June 30,			December 31,
(In millions)	2013			2012			2014			2013
Commercial paper	$	—		$	200		$	—		$	135
Long-term debt due within one year	68			184			68			68
Long-term debt	6,428			6,512			6,362			6,394
Total debt	$	6,496		$	6,896		$	6,430		$	6,597
Cash	$	246		$	684
Cash and cash equivalents							$	1,169		$	264
Equity	$	19,021		$	18,283		$	19,868		$	19,344
Calculation:
Total debt	$	6,496		$	6,896		$	6,430		$	6,597
Minus cash	246			684
Total debt minus cash	6,250			6,212
Minus cash and cash equivalents							1,169			264
Total debt minus cash and cash equivalents							$	5,261		$	6,333
Total debt	6,496			6,896			$	6,430		$	6,597
Plus equity	19,021			18,283			19,868			19,344
Minus cash	246			684
Total debt plus equity minus cash	$	25,271		$	24,495
Minus cash and cash equivalents							1,169			264
Total debt plus equity minus cash and cash equivalents							$	25,129		$	25,677
Cash-adjusted debt-to-capital ratio	25		%	25		%	21		%	25		%

Capital Requirements

On July ~~31, 2013,~~30, 2014, our Board of Directors approved a dividend of 1921 cents per share for the second quarter of ~~2013~~2014, ~~a 12~~an 11 percent increase over the previous quarter, payable September 10, ~~2013~~2014 to stockholders of record at the close of business on August ~~21, 2013.~~20, 2014.

As of June 30, ~~2013~~2014, we plan to make contributions of up to $3952 million to our funded pension plans during the remainder of ~~2013.~~2014.

~~Since January 2006,~~In 2013, our Board of Directors ~~has~~increased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized ~~a common share repurchase program totaling $5~~to $6.2 billion. As of June 30, ~~2013,~~2014, we had repurchased 78a total of 121 million common shares at a cost of ~~$3,222~~$4.7 billion, including 29 million ~~with 66 million~~ shares ~~purchased for $2,922 million prior to the spin-off of our downstream business and 12 million shares acquired~~ at a cost of ~~$300 million~~$1 billion in the ~~third quarter~~first six months of ~~2011.~~2014. The remaining share repurchase authorization as of June 30, 2014 is $1.5 billion. Purchases under the repurchase program may be in either open market transactions, including block purchases, or in

privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity above also contains forward-looking statements regarding the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, including the use of proceeds. The timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government, regulatory and third-party approvals. The expectations with respect to the use of proceeds from the sale of our 10 percent working interest in Block 31 offshore Angola could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of the our exploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. The discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other operating and economic considerations.

Contractual Cash Obligations

As of June 30, ~~2013~~2014, our total contractual cash obligations were consistent with December 31, ~~2012~~2013.

Environmental Matters

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

There have been no significant changes to our environmental matters subsequent to December 31, ~~2012~~2013.

Other Contingencies

~~See Part II Item 1. Legal Proceedings~~Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report, including without limitation statements regarding our operational, financial and growth strategies, planned capital expenditures and the impact thereof, growth activities and expectations, future drilling plans and expected timing, expected production, planned maintenance activities, enhanced completion designs, share repurchase program, operational outlook, future financial position, liquidity and capital resources, expected additions to our Oklahoma acreage position, the planned sale of our Norway business and the expected proceeds and timing thereof, and the plans and objectives of our management for ~~updated information about ongoing litigation.~~our future operations, are forward-looking statements. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, we can give no assurance that these expectations will prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

conditions in the oil and gas industry, including the level of supply or demand for liquid hydrocarbons and natural gas and the impact on the price of liquid hydrocarbons and natural gas;

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

the amount of capital available for exploration and development;

timing of commencing production from new wells;

drilling rig availability;

availability of materials and labor;

the inability to obtain or delay in obtaining necessary government or third-party approvals and permits;

non-performance by third parties of their contractual obligations;

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

changes in safety, health, environmental and other regulations;

other geological, operating and economic considerations; and

3134

other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2013, and those set forth from time to time in our filings with the Securities and Exchange Commission.

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

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 ~~2012~~2013 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 12 and 13 to the consolidated financial statements.

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments, by contract type as of ~~June 30, 2013~~ ~~is provided in the following table.~~

Incremental Change in IFO from a Hypothetical Price Increase of Incremental Change in IFO from a Hypothetical Price Decrease of
10% 25% 10% 25%
Crude oil
Swaps $ (81 ) $ (203 ) $ 81
$ 203
Option Collars (30 ) (92 ) 34
109
Total crude oil $ (111 ) $ (295 ) $ 115
$ 312

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of June 30, ~~2013~~2014 is provided in the following table.


					Incremental							Incremental
					Change in							Change in
(In millions)	Fair Value				Fair Value			Fair Value				Fair Value
Financial assets (liabilities): ^(a)
Interest rate swap agreements	$	6		^(b)	$	3		$	11		^(b)	$	3
Long-term debt, including amounts due within one year	$	(6,991	)	^(b)	$	(241	)	$	(7,133	)	^(b)(c)	$	(215	)


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


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


^(c)	Excludes capital leases.

The ~~aggregate cash flow effect on~~incremental change in fair value of our foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at June 30, ~~2013~~2014 would be $4947 million.

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 Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our company's design and operation of disclosure controls and procedures were effective as of June 30, ~~2013~~2014.

InDuring the ~~first~~second quarter of ~~2013, we completed the update of our existing Enterprise Resource Planning ("ERP") system. This update included a new general ledger, consolidations system and reporting tools. There~~2014, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

3235

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions)	2013			2012			2013			2012			2014			2013			2014			2013
Segment Income
North America E&P	$	221		$	70		$	162		$	174		$	302		$	221		$	544		$	162
International E&P	382			373			835			780			160			170			381			443
Oil Sands Mining	20			50			58			88			55			20			119			58
Segment income	623			493			1,055			1,042			517			411			1,044			663
Items not allocated to segments, net of income taxes	(197		)	(100		)	(246		)	(232		)	(157		)	(170		)	(286		)	(264		)
Income from continuing operations													360			241			758			399
Discontinued operations ^(a)													180			185			931			410
Net income	$	426		$	393		$	809		$	810		$	540		$	426		$	1,689		$	809
Capital Expenditures^(a)
Capital Expenditures ^(b)
North America E&P	$	904		$	1,013		$	1,874		$	1,842		$	1,102		$	904		$	1,969		$	1,874
International E&P	241			202			466			340			115			107			220			194
Oil Sands Mining	97			43			142			95			55			98			123			143
Corporate	15			19			45			63			10			10			13			40
Discontinued operations ^(a)													141			138			251			276
Total	$	1,257		$	1,277		$	2,527		$	2,340		$	1,423		$	1,257		$	2,576		$	2,527
Exploration Expenses
North America E&P	$	76		$	147		$	511		$	253		$	82		$	76		$	139		$	511
International E&P	57			25			87			54			63			49			79			71
Total	$	133		$	172		$	598		$	307		$	145		$	125		$	218		$	582


^(a)	We sold our Angola assets in the first quarter of 2014 and entered into an agreement to sell our Norway business in June 2014. The Angola and Norway businesses are reflected as discontinued operations in all periods presented.


^(b)	Capital expenditures include changes in accruals.

3336

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
Net Sales Volumes 2013 2012 2013 2012
North America E&P

Crude Oil and Condensate (mbbld)
126
85
124
83
Natural Gas Liquids (mbbld)
22
8
21
8
Total Liquid Hydrocarbons 148
93
145
91
Natural Gas (mmcfd)
316
319
328
331
Total North America E&P (mboed)
201
146
200
146

International E&P

Liquid Hydrocarbons (mbbld)

Europe 93
99
96
98
Africa 84
78
82
65
Total Liquid Hydrocarbons 177
177
178
163
Natural Gas (mmcfd)

Europe^(b)
89
102
92
103
Africa 425
399
449
409
Total Natural Gas 514
501
541
512
Total International E&P (mboed)
262
261
268
249

Oil Sands Mining
Synthetic Crude Oil (mbbld)^(c)
43
44
47
44

Total Company (mboed)
506
451
515
439
Net Sales Volumes of Equity Method Investees

LNG (mtd)
5,820
5,467
6,301
5,879
Methanol (mtd)
973
1,268
1,191
1,290


^(b)	~~Includes natural gas acquired for injection and subsequent resale of~~ 8 ~~mmcfd and~~ 17 ~~mmcfd for the~~ ~~second quarters of~~ ~~2013~~ ~~and~~ ~~2012, and~~ 10 ~~mmcfd and~~ 15 ~~mmcfd for the~~ ~~first six months~~ of ~~2013~~ ~~and~~ ~~2012~~.


^(c)	~~Includes blendstocks.~~



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Net Sales Volumes	2014	2013	2014	2013
North America E&P
Crude Oil and Condensate (mbbld)
Bakken	44	35	41	34
Eagle Ford	67	50	65	48
Oklahoma resource basins	2	1	2	1
Other North America	38	40	36	41
Total Crude Oil and Condensate	151	126	144	124
Natural Gas Liquids (mbbld)
Bakken	3	2	2	2
Eagle Ford	16	14	16	13
Oklahoma resource basins	6	4	5	4
Other North America	2	2	4	2
Total Natural Gas Liquids	27	22	27	21
Total Liquid Hydrocarbons (mbbld)
Bakken	47	37	43	36
Eagle Ford	83	64	81	61
Oklahoma resource basins	8	5	7	5
Other North America	40	42	40	43
Total Liquid Hydrocarbons	178	148	171	145
Natural Gas (mmcfd)
Bakken	18	12	17	13
Eagle Ford	111	99	109	91
Oklahoma resource basins	61	48	58	49
Other North America	104	157	113	175
Total Natural Gas	294	316	297	328
Total North America E&P (mboed)	227	201	220	200

3437

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Three Months Ended Six Months Ended
June 30, June 30,
Average Realizations^(d)
2013 2012 2013 2012
North America E&P
Crude Oil and Condensate (per bbl)

$93.75

$89.04
$94.20 $93.25
Natural Gas Liquids (per bbl)

$31.72

$40.54
$33.51 $45.65
Total Liquid Hydrocarbons^(e)

$84.51

$84.72
$85.30 $89.23
Natural Gas (per mcf)

$4.19

$3.42
$4.02 $3.79

International E&P
Liquid Hydrocarbons (per bbl)

Europe
$106.41

$111.12
$111.43 $117.37
Africa
$92.92

$96.84
$94.96 $95.87
Total Liquid Hydrocarbons
$100.00

$104.82
$103.86 $108.80
Natural Gas (per mcf)

Europe
$11.37

$10.05
$12.12 $10.02
Africa^(f)

$0.49

$0.25
$0.50 $0.25
Total Natural Gas
$2.37

$2.25
$2.47 $2.22

Oil Sands Mining
Synthetic Crude Oil (per bbl)

$89.39

$79.31
$84.31 $85.07



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Net Sales Volumes	2014	2013	2014	2013
International E&P
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	31	30	33	34
United Kingdom	13	14	13	17
Libya	—	45	—	39
Total Liquid Hydrocarbons	44	89	46	90
Natural Gas (mmcfd)
Equatorial Guinea	446	401	441	424
United Kingdom^(c)	28	36	29	38
Libya	—	24	1	25
Total Natural Gas	474	461	471	487
Total International E&P (mboed)	123	166	125	171
Oil Sands Mining
Synthetic Crude Oil (mbbld)^(d)	44	43	45	47
Total Continuing Operations (mboed)	394	410	390	418
Discontinued Operations - Angola (mboed)^(a)	—	9	3	9
Discontinued Operations - Norway (mboed)^(a)	70	87	70	88
Total Company (mboed)	464	506	463	515
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,624	5,820	6,601	6,301
Methanol (mtd)	980	973	1,066	1,191


^(c)	Includes natural gas acquired for injection and subsequent resale of 5 mmcfd and 8 mmcfd for the second quarters of 2014 and 2013, and 6 mmcfd and 10 mmcfd for the first six months of 2014 and 2013.


^(d)	Includes blendstocks.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Average Price Realizations ^(e)	2014	2013	2014	2013
North America E&P
Crude Oil and Condensate (per bbl)
Bakken	$93.08	$88.65	$91.43	$89.89
Eagle Ford	99.08	99.40	97.65	101.50
Oklahoma resource basins	101.12	90.51	98.05	90.32
Other North America	93.45	91.32	91.40	89.31
Total Crude Oil and Condensate	95.95	93.75	94.30	94.20
Natural Gas Liquids (per bbl)
Bakken	$45.13	$35.92	$51.04	$38.42
Eagle Ford	30.20	28.09	33.76	28.12
Oklahoma resource basins	33.04	27.99	38.21	34.77
Other North America	54.13	51.05	57.65	53.71
Total Natural Gas Liquids	34.80	31.72	38.75	33.51
Total Liquid Hydrocarbons (per bbl) ^(f)
Bakken	$90.47	$85.96	$89.16	$87.23
Eagle Ford	85.36	83.90	84.78	85.88
Oklahoma resource basins	52.00	47.05	55.04	49.88
Other North America	90.45	88.64	88.97	87.02
Total Liquid Hydrocarbons	86.43	84.51	85.65	85.30
Natural Gas (per mcf)
Bakken	$4.12	$4.47	$6.14	$4.02
Eagle Ford	4.76	4.17	4.83	3.80
Oklahoma resource basins	4.57	4.71	5.01	4.13
Other North America	5.65	4.01	5.35	4.11
Total Natural Gas	5.00	4.19	5.14	4.02


^(e)	Excludes gains ~~and~~or losses on derivative instruments.

^(e)(f)

Inclusion of realized gains ~~(losses)~~ on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations by ~~$1.22~~ ~~per bbl~~$1.26 and ~~$0.45~~$0.50 per bbl for the second quarter and first six months of 2013. There were no ~~realized gains (losses) on~~ crude oil derivative instruments infor the ~~same periods~~second quarter and first six months of ~~2012~~2014.


^(f)	Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment.

3539

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended		Six Months Ended
	June 30,		June 30,
Average Price Realizations ^(e)	2014	2013	2014	2013
International E&P
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea	$59.72	$54.09	$61.12	$60.58
United Kingdom	110.51	101.85	110.02	108.01
Libya	—	117.55	—	122.64
Total Liquid Hydrocarbons	75.41	93.62	75.48	96.65
Natural Gas (per mcf)
Equatorial Guinea^(g)	$0.24	$0.24	$0.24	$0.24
United Kingdom	8.04	10.23	9.07	10.78
Libya	—	4.65	5.45	4.86
Total Natural Gas	0.69	1.24	0.80	1.31
Oil Sands Mining
Synthetic Crude Oil (per bbl)	$94.17	$89.39	$91.27	$84.31
Discontinued Operations - Angola (per boe)^(a)	—	$100.30	$99.82	$103.17
Discontinued Operations - Norway (per boe)^(a)	$108.11	$103.73	$108.09	$108.74

^(g)Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment.

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

~~Litigation~~

In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

~~Environmental~~

We executed a settlement agreement with the North Dakota Department of Health regarding voluntary disclosures of potential Clean Air Act violations made in 2009 relating to our operations on state lands in the Bakken shale and paid a fine of $169,800 in June 2013.

~~SEC Investigation Relating to Libya~~

On May 25, 2011, we received a subpoena issued by the SEC requiring production of documents related to payments made to the government of Libya, or to officials and persons affiliated with officials of the government of Libya. By letter dated April 26, 2013, the SEC further notified us that they completed their investigation and did not intend to recommend any enforcement action in this matter.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our ~~2012~~2013 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 June 30, ~~2013~~2014, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.

Column (a) Column (b) Column (c) Column (d)
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)(b)
Paid per Share
Plans or Programs^(c)

Plans or Programs^(c)
04/01/13 - 04/30/13

12,135
$33.64 —
$1,780,609,536
05/01/13 - 05/31/13 3,795
$32.05 —
$1,780,609,536
06/01/13 - 06/30/13 36,664
$34.84 —
$1,780,609,536
Total 52,594
$34.36 —



	Column (a)	Column (b)	Column (c)	Column (d)
	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)(b)	Paid per Share	Plans or Programs^(c)	Plans or Programs^(c)
04/01/14 - 04/30/14	8,297,968	$35.64	8,233,581	$1,655,706,060
05/01/14 - 05/31/14	4,283,727	$36.34	4,276,263	$1,500,285,529
06/01/14 - 06/30/14	29,876	$37.83	—	$1,500,285,529
Total	12,611,571	$35.88	12,509,844


^(a)	~~27,051~~77,436 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In June ~~2013, 25,543~~2014, 24,291 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.

^(c)

~~We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion.~~ As of June 30, ~~2013~~2014, 78we had repurchased 121 million ~~split-adjusted~~ common shares ~~had been acquired~~ at a cost of ~~$3,222 million,~~$4.7 billion, which includes transaction fees and commissions that are not reported in the table above. Of this total, 6613 million shares ~~had been~~were acquired at a cost of ~~$2,922~~$449 million ~~prior to~~during the ~~spin-off~~second quarter of ~~the downstream business.~~2014.

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

The following exhibits are filed as a part of this report:

Incorporated by Reference
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation. X
3.2 Amended By-laws of Marathon Oil Corporation effective May 29, 2013. X
3.3 Amended By-Laws of Marathon Oil Corporation effective August 1, 2013. X
10.1 Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). 10-Q 10.4 5/4/2012 001-05153
12.1 Computation of Ratio of Earnings to Fixed Charges. X
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. X
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. X
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350. X
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350. X
101.INS XBRL Instance Document. X
101.SCH XBRL Taxonomy Extension Schema. X

101.CAL XBRL Taxonomy Extension Calculation Linkbase. X
101.DEF XBRL Taxonomy Extension Definition Linkbase. X
101.LAB XBRL Taxonomy Extension Label Linkbase. X
101.PRE XBRL Taxonomy Extension Presentation Linkbase. X

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

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

001-05153

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation

10-Q

3.1

8/8/2013

001-05153

3.2

Amended By-Laws of Marathon Oil Corporation effective February 25, 2014

10-K

3.2

2/28/2014

001-05153

3.3

Specimen of Common Stock Certificate

10-K

3.3

2/28/2014

001-05153

4.2

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 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request.

10-K

4.2

2/28/2014

001-05153

10.1

Credit Agreement, dated as of May 28, 2014, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein.

8-K

4.1

06/02/14

001-05153

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.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

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.

Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

3743

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.



August ~~8, 2013~~5, 2014		MARATHON OIL CORPORATION

	By:	~~/s/ Michael K. Stewart~~
		~~Michael K. Stewart~~John R. Sult
		Executive Vice President ~~Finance~~ and ~~Accounting,~~ ~~Controller and Treasurer~~ Chief Financial Officer

3844

Exhibit Index

Incorporated by Reference
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation. X
3.2 Amended By-laws of Marathon Oil Corporation effective May 29, 2013. X
3.3 Amended By-Laws of Marathon Oil Corporation effective August 1, 2013. X
10.1 Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). 10-Q 10.4 5/4/2012 001-05153
12.1 Computation of Ratio of Earnings to Fixed Charges. X
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. X
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. X
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350. X
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350. X
101.INS XBRL Instance Document. X
101.SCH XBRL Taxonomy Extension Schema. X
101.CAL XBRL Taxonomy Extension Calculation Linkbase. X
101.DEF XBRL Taxonomy Extension Definition Linkbase. X
101.LAB XBRL Taxonomy Extension Label Linkbase. X
101.PRE XBRL Taxonomy Extension Presentation Linkbase. X

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

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

001-05153

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation

10-Q

3.1

8/8/2013

001-05153

3.2

Amended By-Laws of Marathon Oil Corporation effective February 25, 2014

10-K

3.2

2/28/2014

001-05153

3.3

Specimen of Common Stock Certificate

10-K

3.3

2/28/2014

001-05153

4.2

10-K

4.2

2/28/2014

001-05153

10.1

8-K

4.1

06/02/14

001-05153

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.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

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.

Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.



	INDEX
		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	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3235
Item 4.	Controls and Procedures	3235
	Supplemental Statistics (Unaudited)	3336
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	3641
Item 1A.	Risk Factors	3641
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3641
Item 4.	Mine Safety Disclosures	3741
Item 6.	Exhibits	3742
	Signatures	3844



(In millions)
Other noncurrent assets	$	1,550
Total assets	1,550
Other current liabilities	58
Deferred credits and other liabilities	39
Total liabilities	$	97



	Six Months Ended June 30, 2012
(In millions)	N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	1,745	$	3,476	$	698	$	5,919
Marketing revenues	1,471		120		15		1,606
Total revenues	$	3,216	$	3,596	$	713	$	7,525
Segment income	$	174	$	780	$	88	$	1,042
Income from equity method investments	1		137		—		138
Depreciation, depletion and amortization	604		428		99		1,131
Income tax provision	100		2,041		30		2,171
Capital expenditures	1,842		340		95		2,277



Remaining Term	Bbls per Day	Weighted Average Price per Bbl	Benchmark
Swaps
July 2013 - December 2013	20,000	$96.29	West Texas Intermediate
July 2013 - December 2013	25,000	$109.19	Brent
Option Collars
July 2013 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
July 2013 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent



	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
	10%			25%			10%		25%
Crude oil
Swaps	$	(81	)	$	(203	)	$	81	$	203
Option Collars	(30		)	(92		)	34		109
Total crude oil	$	(111	)	$	(295	)	$	115	$	312