Edgar Filing: MARATHON OIL CORP

MRO-2014.3.31-10Q

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 March 31, 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 676,077,784 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2014.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended March 31, 2014



	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	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	28
	Supplemental Statistics (Unaudited)	29
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 4.	Mine Safety Disclosures	34
Item 6.	Exhibits	35
	Signatures	36

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
	March 31,
(In millions, except per share data)	2014			2013
Revenues and other income:
Sales and other operating revenues, including related party	$	2,830		$	3,354
Marketing revenues	540			430
Income from equity method investments	137			118
Net gain on disposal of assets	2			109
Other income	20			9
Total revenues and other income	3,529			4,020
Costs and expenses:
Production	613			564
Marketing, including purchases from related parties	540			429
Other operating	114			111
Exploration	76			463
Depreciation, depletion and amortization	697			720
Impairments	17			38
Taxes other than income	98			84
General and administrative	192			172
Total costs and expenses	2,347			2,581
Income from operations	1,182			1,439
Net interest and other	(52		)	(72		)
Income from continuing operations before income taxes	1,130			1,367
Provision for income taxes	590			987
Income from continuing operations	540			380
Discontinued operations	609			3
Net income	$	1,149		$	383
Per Share Data
Basic:
Income from continuing operations	$	0.78		$	0.54
Discontinued operations	$	0.88		$	—
Net income	$	1.66		$	0.54
Diluted:
Income from continuing operations	$	0.77		$	0.54
Discontinued operations	$	0.88		$	—
Net income	$	1.65		$	0.54
Dividends	$	0.19		$	0.17
Weighted average shares:
Basic	693			708
Diluted	696			712

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2014			2013
Net income	$	1,149		$	383
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(30		)	13
Income tax benefit (provision)	10			(5		)
Postretirement and postemployment plans, net of tax	(20		)	8
Foreign currency translation and other
Unrealized loss	—			(1		)
Income tax benefit	—			—
Foreign currency translation and other, net of tax	—			(1		)
Other comprehensive income (loss)	(20		)	7
Comprehensive income	$	1,129		$	390

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)



	March 31,			December 31,
(In millions, except per share data)	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	1,964		$	264
Receivables	2,222			2,134
Inventories	405			364
Other current assets	196			213
Total current assets	4,787			2,975
Equity method investments	1,223			1,201
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $22,336 and $21,895	28,426			28,145
Goodwill	499			499
Other noncurrent assets	1,216			2,800
Total assets	$	36,151		$	35,620
Liabilities
Current liabilities:
Commercial paper	$	—		$	135
Accounts payable	2,382			2,206
Payroll and benefits payable	180			240
Accrued taxes	1,476			1,445
Other current liabilities	208			239
Long-term debt due within one year	68			68
Total current liabilities	4,314			4,333
Long-term debt	6,392			6,394
Deferred tax liabilities	2,517			2,492
Defined benefit postretirement plan obligations	660			604
Asset retirement obligations	2,062			2,009
Deferred credits and other liabilities	401			444
Total liabilities	16,346			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
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 89 million and 73 million shares	(3,445		)	(2,903		)
Additional paid-in capital	6,599			6,592
Retained earnings	16,151			15,135
Accumulated other comprehensive loss	(270		)	(250		)
Total stockholders' equity	19,805			19,344
Total liabilities and stockholders' equity	$	36,151		$	35,620

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2014			2013
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,149		$	383
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(609		)	(3		)
Deferred income taxes	105			45
Depreciation, depletion and amortization	697			720
Impairments	17			38
Pension and other postretirement benefits, net	21			7
Exploratory dry well costs and unproved property impairments	43			404
Net gain on disposal of assets	(2		)	(109		)
Equity method investments, net	(43		)	(48		)
Changes in:
Current receivables	(46		)	39
Inventories	(41		)	(17		)
Current accounts payable and accrued liabilities	129			(71		)
All other operating, net	(28		)	115
Net cash provided by continuing operations	1,392			1,503
Net cash provided by discontinued operations	78			25
Net cash provided by operating activities	1,470			1,528
Investing activities:
Additions to property, plant and equipment	(1,051		)	(1,321		)
Disposal of assets	2,123			312
Investments - return of capital	20			18
Investing activities of discontinued operations	(49		)	(54		)
All other investing, net	5			8
Net cash provided by (used in) investing activities	1,048			(1,037		)
Financing activities:
Commercial paper, net	(135		)	(200		)
Debt repayments	—			(114		)
Purchases of common stock	(551		)	—
Dividends paid	(133		)	(120		)
All other financing, net	9			21
Net cash used in financing activities	(810		)	(413		)
Effect of exchange rate changes on cash	(8		)	6
Net increase in cash and cash equivalents	1,700			84
Cash and cash equivalents at beginning of period	264			684
Cash and cash equivalents at end of period	$	1,964		$	768

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.

As the result of the sale of our Angola assets (see Note 5), the Angola operations 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.

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

2. Accounting Standards

Not Yet Adopted

In April 2014, the Financial Accounting Standards Board ("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 which requires that an unrecognized tax benefit (or a portion 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 was effective for us beginning in the first quarter of 2014 and is required to be applied prospectively. Adoption of this standard did not 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. This accounting standards update was effective for us beginning in the first quarter of 2014 and is required to be applied retrospectively. 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 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. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $3 million recorded at March 31, 2014, consistent with December 31, 2013. 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 $741 million as of March 31, 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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.



	Three Months Ended March 31,
	2014				2013
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	540	$	540	$	380	$	380
Discontinued operations	609		609		3		3
Net income	$	1,149	$	1,149	$	383	$	383

Weighted average common shares outstanding	693		693		708		708
Effect of dilutive securities	—		3		—		4
Weighted average common shares, including
dilutive effect	693		696		708		712
Per share:
Income from continuing operations	$	0.78	$	0.77	$	0.54	$	0.54
Discontinued operations	$	0.88	$	0.88	$	—	$	—
Net income	$	1.66	$	1.65	$	0.54	$	0.54

The per share calculations above exclude 5 million and 6 million stock options for the first three months of 2014 and 2013 as they were antidilutive.

5. Dispositions

2014 - International Exploration and Production ("E&P") Segment

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 March 31,
(In millions)	2014		2013
Revenues applicable to discontinued operations	$	58	$	86
Pretax income from discontinued operations ^(a)	$	51	$	41
Pretax gain on disposition of discontinued operations	$	470	$	—

(a) After-tax income of $33 million and $3 million for the three months ended March 31, 2014 and 2013.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Assets held for sale in the December 31, 2013 consolidated balance sheet related to the Angola Block 31 disposition that was pending at that date included:



(In millions)	December 31, 2013
Other current assets	$	41
Other noncurrent assets	1,647
Total assets	$	1,688
Other current liabilities	$	25
Deferred credits and other liabilities	43
Total liabilities	$	68

2013 - North America E&P Segment

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. A $46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013. An additional $9 million pretax gain was recorded after finalizing closing adjustments in the second quarter of 2013.

6. Segment Information

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


•	North America E&P ("N.A. E&P") – explores for, produces and markets 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, 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. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on dispositions or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

As discussed in Note 5, in the first quarter of 2014, we sold our Angola assets. The Angola operations are reflected as discontinued operations and excluded from the International E&P segment in all periods presented.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,392	$	1,061	$	377	$	—			$	2,830
Marketing revenues	440		69		31		—				540
Total revenues	1,832		1,130		408		—				3,370
Income from equity method investments	—		137		—		—				137
Net gain on disposal of assets and other income	3		17		2		—				22
Less:
Production expenses	211		171		231		—				613
Marketing costs	440		69		31		—				540
Exploration expenses	57		19		—		—				76
Depreciation, depletion and amortization	515		125		45		12				697
Impairments	17		—		—		—				17
Other expenses ^(a)	110		54		13		129			^(c)	306
Taxes other than income	90		3		5		—				98
Net interest and other	—		—		—		52				52
Income tax provision (benefit)	153		512		21		(96		)		590
Segment income/Income from continuing operations	$	242	$	331	$	64	$	(97	)		$	540
Capital expenditures ^(b)	$	867	$	171	$	68	$	3			$	1,109


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


^(b)	Includes accruals.


^(c)	Includes pension settlement loss of $63 million.



	Three Months Ended March 31, 2013
								Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,215		$	1,801	$	388	$	(50	)	^(c)	$	3,354
Marketing revenues	345			85		—		—				430
Total revenues	1,560			1,886		388		(50		)		3,784
Income from equity method investments	—			118		—		—				118
Net gain on disposal of assets and other income	—			16		—		102				118
Less:
Production expenses	184			109		271		—				564
Marketing costs	347			82		—		—				429
Exploration expenses	435			28		—		—				463
Depreciation, depletion and amortization	478			180		52		10				720
Impairments	23			—		—		15				38
Other expenses ^(a)	106			65		8		104				283
Taxes other than income	76			2		6		—				84
Net interest and other	—			—		—		72				72
Income tax provision (benefit)	(30		)	1,100		13		(96		)		987
Segment income/Income from continuing operations	$	(59	)	$	454	$	38	$	(53	)		$	380
Capital expenditures ^(b)	$	970		$	171	$	45	$	30			$	1,216


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


^(b)	Includes accruals.


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:



	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2014			2013			2014			2013
Service cost	$	14		$	14		$	1		$	1
Interest cost	16			15			3			3
Expected return on plan assets	(18		)	(17		)	—			—
Amortization:
– prior service cost (credit)	1			2			(1		)	(2		)
– actuarial loss	6			13			—			—
Net settlement loss^(a)	63			—			—			—
Net periodic benefit cost	$	82		$	27		$	3		$	2

(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 first quarter of 2014.

During the first quarter of 2014, we recorded the effects of partial settlements of our United States ("U.S.") pension plans and we remeasured the plans' assets and liabilities as of March 31, 2014. As a result, we recognized a pretax increase of $36 million in actuarial losses, net of settlement loss, in other comprehensive income for the three months ended March 31, 2014.

During the first three months of 2014, we made contributions of $20 million to our funded pension plans. We expect to make additional contributions up to an estimated $57 million to our funded pension plans over the remainder of 2014. Current benefit payments related to unfunded pension and other postretirement benefit plans were $40 million and $4 million during the first three months of 2014.

8. Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement, net of any foreign currency hedge effects. 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 is reported in the “Not Allocated to Segments” column of the tables in Note 6.

Our effective income tax rates on continuing operations for the first three months of 2014 and 2013 were 52 percent and 72 percent. These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway in 2014 and 2013 and Libya in 2013, where the tax rates are in excess of the U.S. statutory rate. The decrease in the effective tax rate on continuing operations in the first three months of 2014 is due to higher projected annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya.

The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2014 and 2013. Excluding Libya, the effective tax rates on continuing operations would be 53 percent and 64 percent for the first three months of 2014 and 2013. In Libya, where the statutory tax rate is in excess of 90 percent, we have had no oil liftings since July 2013 due to third-party labor strikes at the Es Sider oil terminal and there remains uncertainty around future production and sales levels. Reliable estimates of 2014 and 2013 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the first three months of 2014 and 2013, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. Inventories

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



	March 31,		December 31,
(In millions)	2014		2013
Liquid hydrocarbons, natural gas and bitumen	$	68	$	55
Supplies and other items	337		309
Inventories, at cost	$	405	$	364

10. Property, Plant and Equipment



	March 31,			December 31,
(In millions)	2014			2013
North America E&P	$	27,309		$	26,755
International E&P	12,519			12,428
Oil Sands Mining	10,514			10,436
Corporate	420			421
Total property, plant and equipment	50,762			50,040
Less accumulated depreciation, depletion and amortization	(22,336		)	(21,895		)
Net property, plant and equipment	$	28,426		$	28,145

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 and there remains uncertainty around future production and sales levels. We have had no oil liftings in Libya since July 2013. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. As of March 31, 2014, our net property, plant and equipment investment in Libya is approximately $770 million.

Exploratory well costs capitalized greater than one year after completion of drilling were $153 million as of March 31, 2014, a net decrease of $128 million from December 31, 2013. This net decrease was the result of: a decrease of $153 million due to the sale of our interests in Angola Blocks 31 and 32, a decrease of $26 million due to the commencement of drilling at the Boyla development offshore Norway, and an increase of $51 million related to the Shenandoah prospect in the Gulf of Mexico, with costs incurred primarily in 2012 and 2013, which has now been suspended for more than one year. Additional appraisal drilling on the non-operated Shenandoah prospect is expected to begin in 2014.

11. Fair Value Measurements

Fair Values - Recurring

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



	March 31, 2014
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Interest rate	$	—	$	7	$	—	$	—	$	7
Foreign currency	—		10		—		—		10
Derivative instruments, assets	$	—	$	17	$	—	$	—	$	17
Derivative instruments, liabilities
Foreign currency	$	—	$	2	$	—	$	—	$	2
Derivative instruments, liabilities	$	—	$	2	$	—	$	—	$	2

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		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.

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 March 31,
	2014				2013
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	17	$	—	$	38

All long-lived assets held for use that were impaired in the first quarters of 2014 and 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.

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 quarter of 2014, we recorded an additional $17 million impairment 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.

Other impairments of long-lived assets held for use by our North America E&P segment in the first quarter of 2013 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 March 31, 2014 and December 31, 2013.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	March 31, 2014				December 31, 2013
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	154	$	147	$	154	$	147
Total financial assets	154		147		154		147
Financial liabilities
Other current liabilities	13		13		13		13
Long-term debt, including current portion^(a)	7,020		6,427		6,922		6,427
Deferred credits and other liabilities	153		149		149		147
Total financial liabilities	$	7,186	$	6,589	$	7,084	$	6,587

^(a) Excludes capital leases.

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

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

12. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate 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 March 31, 2014 and December 31, 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 March 31, 2014 and December 31, 2013.



	March 31, 2014
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	7	$	—	$	7	Other noncurrent assets
Foreign currency	10		—		10		Other current assets
Total Designated Hedges	$	17	$	—	$	17



	March 31, 2014
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	2	$	2	Other current liabilities
Total Designated Hedges	$	—	$	2	$	2

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	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

The following table presents by maturity date, information about our interest rate swap agreements as of March 31, 2014 and December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.



	Aggregate Notional		March 31, 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	4.49	%	4.50	%

As of March 31, 2014 and December 31, 2013, our foreign currency forwards had an aggregate notional amount of 4,261 million and 2,387 million Norwegian Kroner at weighted average forward rates of 6.069 and 6.060. These forwards hedge our current Norwegian tax liability and those outstanding at March 31, 2014 have settlement dates through August 2014.

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)
		Three Months Ended March 31,
(In millions)	Income Statement Location	2014			2013
Derivative
Interest rate	Net interest and other	$	(1	)	$	(3	)
Foreign currency	Provision for income taxes	$	3		$	(25	)
Hedged Item
Long-term debt	Net interest and other	$	1		$	3
Accrued taxes	Provision for income taxes	$	(3	)	$	25

Derivatives not Designated as Hedges

The impact of all commodity derivative instruments not designated as hedges appears in sales and other operating revenues in our consolidated statements of income and was a net loss of $55 million in the first quarter of 2013.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. 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 three months of 2014:



	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	901,447		^(a)		$33.94	138,851			$33.85
Options Exercised/Stock Vested	(289,709	)			$20.89	(368,263	)		$33.60
Canceled	(246,363	)			$33.60	(201,215	)		$31.33
Outstanding at March 31, 2014	18,470,262				$27.61	3,601,261			$31.72

^(a) The weighted average grant date fair value of stock option awards granted was $10.47 per share.

Stock-based performance unit awards

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

14. 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 March 31,
(In millions)	2014			2013			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Postretirement and postemployment plans
Amortization of actuarial loss	$	(6	)	$	(13	)	General and administrative
Net settlement loss	(63		)	—			General and administrative
	(69		)	(13		)	Income from operations
	23			5			Provision for income taxes
Total reclassifications for the period	$	(46	)	$	(8	)	Net income

15. Stockholders' Equity

During the first quarter of 2014, we acquired 16 million common shares at a cost of $551 million under our share repurchase program.

16. Supplemental Cash Flow Information



	Three Months Ended March 31,
(In millions)	2014			2013
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	56		$	61
Income taxes paid to taxing authorities	453			1,003
Commercial paper, net:
Commercial paper - issuances	$	2,235		$	200
- repayments	(2,370		)	(400		)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	37		$	27
Change in capital expenditure accrual	58			(105		)
Asset retirement obligations assumed by buyer	43			88
Receivable for disposal of assets	44			50

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

17. 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.

Contractual commitments – At March 31, 2014, Marathon’s contract commitments to acquire property, plant and equipment were $1,190 million.

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

We are an international energy company based in Houston, Texas, with activities in North America, Europe, Africa and Asia. 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 – 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 ("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 and Analysis of Financial Condition and Results of Operations, contain forward-looking statements concerning trends or events potentially affecting 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 forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2013 Annual Report on Form 10-K. We assume no duty to update these statements as to any future date.

Key Operating and Financial Activities

In the first quarter of 2014, notable activities were:


•	Increased net income per diluted share to $1.65, which includes $0.83 per diluted share related to the after-tax gain on the sale of our Angola assets, an increase of over 200 percent from the same quarter of last year


•	Increased income from continuing operations per diluted share to $0.77, up 43 percent from the same quarter of last year


•	Three high-quality U.S. resource plays averaged net production of 154 thousand barrels of oil equivalent per day ("mboed"), up 26 percent from the first quarter of 2013


◦	Eagle Ford downspacing results continued to consistently outperform modeled type curves


◦	Austin Chalk and Eagle Ford co-development continuing on plan with completion of first 2014 Austin Chalk well at 30-day initial production ("IP") rate of 1,600 barrels of oil equivalent per day ("boed")


◦	Bakken and Three Forks co-development progressing with high density pilots delivering strong results; testing eight wells per 1,280-acre drilling spacing unit


◦	Bakken recompletions program delivered five wells with initial 24-hour and 30-day IP rates exceeding expectations


◦	South Central Oklahoma Oil Province ("SCOOP") extended-reach (XL) wells delivering strong results with two wells at 30-day IP rates of up to 1,550 boed


•	Recorded 97 percent average operational availability for operated assets


•	Marketing of North Sea businesses on schedule; bids due in second quarter


•	Closed on sales of Angola Blocks 31 and 32 for aggregate cash proceeds of approximately $2 billion, resulting in after-tax gain of $576 million


•	Completed second phase of $1 billion share repurchase; initiated additional $500 million share repurchase

Significant second quarter activity through May 7, 2014 includes:


•	Substantially completed additional $500 million share repurchase

Overview and Outlook

Our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 514 mboed for the first quarter of 2013. Excluding Libya, where we had no oil liftings in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal, our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 476 mboed for the first quarter of 2013. See Supplemental Statistics for a tabular presentation of net sales volumes by product and location for each period.

North America E&P

Production

Net liquid hydrocarbon and natural gas sales volumes averaged 213 mboed in the first quarter of 2014 compared to 198 mboed in the first quarter of 2013, for an increase of approximately 8 percent. Net liquid hydrocarbon sales volumes increased 22 thousand barrels per day ("mbbld") for the first quarter of 2014, primarily reflecting the continued growth across our three U.S. resource plays partially offset by natural declines in Gulf of Mexico production. Extreme winter weather impacts on availability and completion operations negatively impacted production in the first quarter of 2014. Net natural gas sales volumes decreased 40 million cubic feet per day ("mmcfd") during the same period, 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. These decreases were somewhat offset by increases in associated natural gas production from our U.S. resource plays.

Eagle Ford – Average net sales volumes from Eagle Ford were 96 mboed in the first quarter of 2014 compared to 72 mboed in the same period of 2013, for an increase of 33 percent. Approximately 65 percent of the first quarter of 2014 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 18 percent was natural gas.

Individual well results were strong during the quarter and continued to consistently outperform the modeled type curves. With the transition to higher density pad drilling, from an average of three to four wells per pad, coupled with a period of rebuilding uncompleted well inventory, the number of wells we brought to sales was lower compared to the fourth quarter of 2013. During the first quarter of 2014, we reached total depth on 83 gross operated wells and brought 49 gross operated wells to sales compared to 76 reaching total depth and 69 brought to sales in the first quarter of 2013. Our first quarter average spud-to-total depth time was 14 days, which reflected the addition and ramp up of three new rigs and an increased number of wells with longer laterals, compared to 12 days in the same period of 2013.

We continued to progress co-development opportunities in the Austin Chalk. In early April, we brought online an Austin Chalk appraisal well, the Children Weston 4H, with a 30-day IP rate of 1,600 boed (76 percent liquid hydrocarbons) constrained at a 16/64 choke. This is our sixth Austin Chalk producer which continues the further appraisal of full Austin Chalk potential. Two additional Austin Chalk wells are waiting on completion and three more pilot groups, with a total of six Austin Chalk wells, are currently drilling.

Bakken – Average net sales volumes from the Bakken shale were 43 mboed in the first quarter of 2014 compared to 37 mboed in the same period of 2013, for an increase of 16 percent. Our Bakken production averages approximately 90 percent crude oil, 4 percent NGLs and 6 percent natural gas. During the first quarter of 2014, we reached total depth on 16 gross operated wells and brought 15 gross operated wells sales. Our first quarter average time to drill a well was 18 days spud-to-total depth, compared to 16 days in the same period of 2013. Both our drilling and completion activities were impacted by extraordinary winter weather in the first quarter of 2014.

We recompleted five wells during the first quarter of 2014 with favorable results in the Myrmidon area and have recently expanded south in the Hector area. We continue high density pilots to test 320-acre spacing for co-development with four Middle Bakken and four Three Forks wells per 1,280-acre spacing unit. Further high density pilots with up to 12 wells per 1,280-acre spacing unit are planned by the end of 2014.

Oklahoma resource basins – Net sales volumes from the Oklahoma resource basins averaged 15 mboed in the first quarter of 2014, for an increase of 15 percent over the same period of 2013. Importantly, liquid hydrocarbon volumes increased approximately 28 percent compared to the first quarter of 2013. During the first quarter of 2014, we reached total depth on five gross operated wells and brought four gross SCOOP wells to sales. The 30-day IP rates for the two SCOOP XL wells were 990 boed (70 percent liquid hydrocarbons) and 1,550 boed (66 percent liquid hydrocarbons). We have accumulated more than 100,000 net acres in the SCOOP area.

We continue to test other horizons in Oklahoma with two operated wells producing in the Southern Mississippi Trend and the first of two Granite Wash horizontal wells online. Two additional wells in the Southern Mississippi Trend are scheduled to spud in the second quarter of 2014.

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

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

We expect the second appraisal well on the non-operated Shenandoah prospect to be spud in the second quarter of 2014. The well will be located on Walker Ridge Block 51, in which we hold a 10 percent working interest.

We have farmed into the Perseus prospect located on Desoto Canyon Blocks 143, 187, 188, 230 and 231. A well is anticipated to spud in the second half of 2014. We hold a 30 percent non-operated working interest.

International E&P

Production

Net liquid hydrocarbon and natural gas sales volumes averaged 197 mboed during the first quarter of 2014 compared to 265 mboed in the same period of 2013, a 26 percent decrease. We had no oil liftings in Libya in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal. Excluding Libya, net sales volumes decreased 13 percent in the first quarter of 2014 compared to the first quarter of 2013 primarily as a result of significant unplanned downtime at the non-operated Foinaven field in the United Kingdom ("U.K.") and unplanned downtime at the methanol plant in Equatorial Guinea, as well as natural decline from North Sea assets and production curtailments at Alvheim in Norway due to severe winter weather.

Equatorial Guinea – Average net sales volumes were 108 mboed in the first quarter of 2014 compared to 111 mboed in the same period of 2013. During the first quarter of 2014, work was completed on scheduled offshore riser repairs, an unplanned repair at the methanol plant, as well as a planned 8-day partial shut-down at the LNG plant, which was accomplished ahead of schedule and under budget.

Norway – Average net sales volumes from Norway decreased 20 percent to 70 mboed in the first quarter of 2014 compared to 88 mboed in the same period of 2013, primarily reflecting natural field production decline. Alvheim was also impacted in the first quarter of 2014 by severe winter weather which resulted in eight days of curtailed production.

United Kingdom – Average net sales volumes were 18 mboed in the first quarter of 2014 compared to 28 mboed in the same period of 2013, a 36 percent decrease as a result of reliability issues at the non-operated Foinaven field, as well as natural decline and a delayed reinstatement of gas compression at Brae. During the second quarter of 2014, a turnaround is planned at Brae. The reliability issues at Foinaven continue into the second quarter of 2014 and will impact production and the timing of future liftings. Additionally, we expect a planned turnaround at Foinaven to begin in the second quarter and extend into the third quarter of 2014.

Libya – We have had no oil liftings in Libya since July 2013 due to ongoing third-party labor strikes at the Es Sider oil terminal. Despite reported progress at other terminals, the Es Sider oil terminal remains closed.

Exploration

Kurdistan Region of Iraq – The Jisik-1 exploration well was spud on the Harir Block in December 2013. We expect the well to reach a projected total depth of 13,100 feet in the second quarter of 2014. Following the successful 2013 Mirawa-1 discovery, the Mirawa-2 appraisal well is expected to spud in the third quarter of 2014. We hold a 45 percent operated working interest in the Harir Block.

The Atrush-4 development well reached total depth on the Atrush Block in January 2014. Well testing was completed in April and the well has been suspended as a future producer. The Chiya Khere-5 development well (formerly Atrush-5), included in the previously approved Atrush development plan, is expected to spud in the second quarter of 2014. First oil from the Atrush Block is expected in 2015. We hold a 15 percent non-operated working interest in the Atrush Block.

Kenya – The Sala-1 exploration well was spud in February 2014 on the eastern side of Block 9, where previous wells drilled had confirmed a working petroleum system. The Sala-1 is expected to reach a total depth of approximately 11,300 feet in the second quarter of 2014. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development.

Ethiopia – The Shimela-1 spud in March 2014 on the South Omo Block and is expected to reach a total depth of 8,850 feet in the second quarter of 2014. We hold a 20 percent non-operated interest in the South Omo Block.

We increased our acreage in Ethiopia through a farm-in to the Rift Basin Area Block with 10.5 million gross acres. We hold a 50 percent non-operated working interest in the block with the option to operate if a discovery is made.

Gabon – In late October 2013, we were the high bidder as operator of the G13 deepwater block in the pre-salt play offshore Gabon. We have received a Model Production Sharing Contract ("PSC") from the Gabonese government and negotiations toward a final PSC are ongoing. Award of the block is subject to government approval.

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

Oil Sands Mining

Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the AOSP. Our net synthetic crude oil sales volumes were 47 mbbld in the first quarter of 2014 compared to 51 mbbld in the same period of 2013, as a result of lower mine reliability and nine days of planned mine maintenance. We expect a planned turnaround in the second quarter of 2014.

Acquisitions and Dispositions

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. See Note 5 to the consolidated financial statements for information about these dispositions.

The above discussions include forward-looking statements with respect to future drilling plans, exploration drilling activity in the Gulf of Mexico, Ethiopia, the Kurdistan Region of Iraq and Kenya, the timing of first production for the Atrush Block, the award of one block in Gabon, planned turnarounds at Foinaven, Brae, and oil sands mining, the possible sale of the U.K. and Norway businesses, and the common stock repurchase program. The reported average number of days to drill a well may not be indicative of the number of days to drill a well in the future. The current or initial production rates may not be indicative of future production rates. Factors that could potentially affect future drilling plans, exploration drilling activity in the Gulf of Mexico, Ethiopia, the Kurdistan Region of Iraq and Kenya, and the timing of first production for the Atrush Block 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, 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 award of the block in Gabon is subject to government approval and negotiation of an exploration and production sharing contract. The planned turnarounds at Foinaven, Brae, and oil sands mining are based on current expectations and good faith projections and are not guarantees of future performance. The possible sale of the U.K. and Norway businesses is subject to the identification of one or more buyers, board approval, successful negotiations, and execution of definitive agreements. The common stock repurchase program could be affected by changes in the prices of and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our exploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. 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 and natural gas that we produce significantly impact our revenues and cash flows. The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the first quarters of 2014 and 2013.



	Three Months Ended March 31,
Benchmark	2014		2013
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)		$98.62		$94.36
Brent (Europe) crude oil (Dollars per barrel)		$108.17		$112.49
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))^(a)		$4.94		$3.34


^(a)	Settlement date average.

North America E&P

Liquid hydrocarbons – The quality, location, and composition of our liquid hydrocarbon production mix can cause our 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 has historically produced higher value products; therefore, light sweet crude is considered of higher quality and 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 light sweet crude has been increasing. In the first quarter of 2014, the percentage of our U.S. crude oil and condensate production that was sweet averaged 79 percent compared to 74 percent in the same period of 2013.

Location – In recent years, crude oil sold along the U.S. Gulf Coast, such as that from the Eagle Ford, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI and has historically tracked closely to Brent, while production from inland areas farther from large refineries has been priced lower. The average WTI discount to Brent has narrowed in 2014. In first quarter of 2014, the WTI discount to Brent was $9.55 compared to $18.13 in the same period of 2013. As a result of significant increases in U.S. production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.

Composition – The proportion of our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in the first quarter of 2014 compared to 14 percent in the same period of 2013.

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 48 percent higher for the first quarter of 2014 than in the same period of 2013.

International E&P

Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark, which was 4 percent lower in the first quarter of 2014 than in the same period of 2013.

Natural gas – Our major international natural gas-producing regions are Europe 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 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 reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third has historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS"). The WCS discount to WTI in the first quarter of 2014 decreased 28 percent when compared to the same period of 2013.

The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. 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.

The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarters of 2014 and 2013:



	Three Months Ended March 31,
Benchmark	2014	2013
WTI crude oil (Dollars per barrel)	$98.62	$94.36
WCS crude oil (Dollars per barrel)^(a)	$75.55		$62.41
AECO natural gas sales index (Dollars per mmbtu)^(b)	$4.99		$3.16


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


^(b)	Monthly average AECO day ahead index.

Results of Operations

Consolidated Results of Operation

Net income per diluted share was $1.65 in the first quarter of 2014, up over 200 percent from the same period of 2013 primarily due to the $0.83 per diluted share after-tax gain on the sale of our Angola assets and a reduction in exploration expenses. The effective tax rate for continuing operations was 52 percent in the first quarter of 2014 compared to 72 percent in the first quarter of 2013. This decrease was primarily due to higher projected 2014 annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya in the first quarter of 2014, compared to pretax income in Libya during the same period of 2013, where the tax rates are in excess of 90 percent. Income from continuing operations per diluted share was $0.77, an increase of 43 percent from the first quarter of 2013, primarily due to the reduction in exploration expenses and the change in the income mix to lower tax jurisdictions.

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



	Three Months Ended March 31,
(In millions)	2014		2013
Sales and other operating revenues, including related party
North America E&P	$	1,392	$	1,215
International E&P	1,061		1,801
Oil Sands Mining	377		388
Segment sales and other operating revenues, including related party	2,830		3,404
Unrealized loss on crude oil derivative instruments	—		(50		)
Sales and other operating revenues, including related party	$	2,830	$	3,354

North America E&P sales and other operating revenues increased $177 million in the first quarter of 2014 compared to the same period of 2013 primarily due to higher net liquid hydrocarbon sales volumes resulting from the continued growth across our three U.S. resource plays partially offset by slightly lower liquid hydrocarbon price realizations compared to the same period of 2013.

The following table gives details of net sales volumes and average price realizations of our North America E&P segment:



	Three Months Ended March 31,
	2014	2013
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld) ^(a)	163	141
Liquid hydrocarbon average price realizations (per bbl) ^{(b) (c)}	$84.79	$86.14
Net crude oil and condensate sales volumes (mbbld)	138	121
Crude oil and condensate average price realizations (per bbl) ^(b)	$92.48	$94.68
Net natural gas liquids sales volumes (mbbld)	25	20
Natural gas liquids average price realizations (per bbl) ^(b)	$43.11	$35.48
Net natural gas sales volumes (mmcfd)	300	340
Natural gas average price realizations (per mcf)^(b)	$5.28	$3.86


^(a)	Includes crude oil, condensate and natural gas liquids.


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


^(c)	Inclusion of realized losses on crude oil derivative instruments would have decreased average liquid hydrocarbon price realizations by $0.31 per bbl for the first three months of 2013. There were no crude oil derivative instruments for the first three months of 2014.

International E&P sales and other operating revenues decreased $740 million in the first quarter of 2014 from the comparable prior-year period. The decrease in the first quarter of 2014 was primarily due to lower liquid hydrocarbon sales volumes, primarily in Libya and Norway as previously discussed, and lower liquid hydrocarbon price realizations.

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



	Three Months Ended March 31,
	2014	2013
International E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld)^(a)	110	171
Liquid hydrocarbon average price realizations (per bbl)	$96.49	$107.79
Net natural gas sales volumes (mmcfd) ^(b)	518	568
Natural gas average price realizations (per mcf)	$1.98	$2.57


^(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)	Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 11 mmcfd for the first quarters of 2014 and 2013.

Oil Sands Mining sales and other operating revenues decreased $11 million in the first quarter of 2014 from the comparable prior-year period.

The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:



	Three Months Ended March 31,
	2014	2013
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld) ^(a)	47	51
Synthetic crude oil average price realizations (per bbl)	$88.50	$79.98


^(a)	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. These crude oil derivatives resulted in a net unrealized loss of $50 million in the first quarter of 2013. There were no crude oil derivative instruments in the first quarter of 2014.

Marketing revenues increased $110 million in the first quarter of 2014 from the comparable prior-year period. The increase related primarily to North America E&P segment marketing activities, which serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, and which increased in 2014 as a result of market dynamics.

Income from equity method investments increased $19 million in the first quarter of 2014 versus the first quarter of 2013 primarily due to higher LNG average price realizations.

Net gain on disposal of assets in the first quarter of 2013 included a $98 million pretax gain on the sale of our interest in the Neptune gas plant, a $46 million pretax gain on the sale of our remaining assets in Alaska and a $43 million pretax loss on the conveyance of our interest in the Marcellus natural gas shale play to the operator. See Note 5 to the consolidated financial statements for information about these dispositions.

Production expenses increased $49 million in the first quarter of 2014 compared to the same quarter in 2013. North America E&P production expenses increased $27 million primarily related to increased net sales volumes in the U.S. resource plays. International E&P production expenses increased $62 million, including $40 million for non-recurring workover activity in Norway and $11 million for non-recurring riser repairs in Equatorial Guinea. These one-time charges combined with decreased net sales volumes substantially increased the production expense rate for the International E&P segment below. OSM production expenses decreased $40 million primarily due to lower contract services and contract labor in the first quarter of 2014 and higher turnaround costs in the same quarter of 2013, however lower net sales volumes caused the production expense rate to increase slightly.

The following table provides production expense rates for each segment:



	Three Months Ended March 31,
($ per boe)	2014		2013
North America E&P		$11.02		$10.35
International E&P		$9.67		$4.57
Oil Sands Mining ^(a)	$47.54		$46.29


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

Marketing expenses increased $111 million in the first quarter of 2014 from the same period of 2013, consistent with the marketing revenues change discussed above.

Exploration expenses were $387 million lower in the first quarter of 2014 than in the same quarter in 2013, primarily due to higher non-cash unproved property impairments in our North America E&P segment in the first quarter of 2013 related to Eagle Ford shale leases that either had expired or that we do not expect to drill or extend.

The following table summarizes the components of exploration expenses:



	Three Months Ended March 31,
(In millions)	2014		2013
Unproved property impairments	$	41	$	383
Dry well costs	2		21
Geological and geophysical	11		28
Other	22		31
Total exploration expenses	$	76	$	463

Depreciation, depletion and amortization (“DD&A”) decreased $23 million in the first quarter of 2014 from the comparable prior-year period. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs. Decreased DD&A in the first quarter of 2014 primarily reflects the impact of lower International E&P and OSM net sales volumes partially offset by higher North America E&P net sales volumes.

The DD&A rate (expense per boe), which is impacted by changes in reserves and capitalized costs, can also cause changes to our DD&A. The DD&A rates for the International E&P and Oil Sands Mining segments decreased in the first quarter of 2014 from the same quarter of 2013 primarily due to reserve additions in Norway and Canada in the latter half of 2013. The following table provides DD&A rates for each segment:



	Three Months Ended March 31,
($ per boe)	2014		2013
DD&A rate
North America E&P	$	26.88	$	26.83
International E&P	$	7.04	$	7.50
Oil Sands Mining	$	11.70	$	12.13

Impairments in the first quarter of 2014 included $17 million related to the Ozona development in the Gulf of Mexico. The first quarter of 2013 included a $21 million impairment for the Ozona development and a $15 million impairment for the Power River Basin.

Taxes other than income include production, severance and ad valorem taxes in the United States which tend to increase or decrease in relation to sales volumes and revenue. With the increase in North America E&P revenues and net sales volumes, taxes other than income increased $14 million in the first quarter of 2014 from the first quarter of 2013.

General and administrative expenses increased $20 million in the first quarter of 2014 from the same period in 2013. The increase is primarily due to a $63 million charge related to partial settlements of our U.S. pension plans, partially offset by lower employee related costs.

Net interest and other decreased $20 million in the first quarter of 2014 from the comparable period of 2013 primarily due to a dividend received from a mutual insurance company of which we are an owner, and increased capitalized interest.

Provision for income taxes decreased $397 million in the first quarter of 2014 from the comparable period of 2013 primarily as a result of lower pretax income, primarily in Libya.

production and sales levels. Reliable estimates of 2014 and 2013 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the first three months of 2014 and 2013, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya.

Discontinued operations are presented net of tax. In the first quarter of 2014, we closed the sale of our Angola assets. Our Angola operations are reflected as discontinued operations in all periods presented. See Note 5 to the consolidated financial statements.

Segment Income

Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments.



	Three Months Ended March 31,
(In millions)	2014			2013
North America E&P	$	242		$	(59	)
International E&P	331			454
Oil Sands Mining	64			38
Segment income	637			433
Items not allocated to segments, net of income taxes	(97		)	(53		)
Income from continuing operations	540			380
Discontinued operations ^(a)	609			3
Net income	$	1,149		$	383


^(a)	In the first quarter of 2014, we closed the sale of our Angola assets. The Angola business is reflected as discontinued operations in all periods presented.

North America E&P segment income increased $301 million after-tax in the first quarter of 2014 compared to the same period of 2013. The increase is primarily due to lower exploration expenses and higher net sales volumes from our U.S. resource plays. In the first quarter of 2014, exploration expenses were $57 million, compared to $435 million in the same period of 2013, primarily related to unproved property impairments, as previously discussed.

International E&P segment income decreased $123 million after-tax in the first quarter of 2014 compared to the same period of 2013. The decrease is primarily a result of lower net sales volumes in Libya, Norway and the U.K. and higher production expenses in Norway and Equatorial Guinea, partially offset by reduced DD&A associated with the lower volumes and lower income taxes, primarily in Libya. Production expenses were higher in the first quarter of 2014 by approximately $40 million due to non-recurring workover activity in Norway, and by $11 million due to non-recurring riser repairs in Equatorial Guinea.

Oil Sands Mining segment income increased $26 million after-tax in the first quarter of 2014 compared to the same period of 2013. The increase was primarily a result of lower contract services and contract labor in the first quarter of 2014 and higher turnaround costs in the same quarter of 2013. The favorable impacts of higher price realizations and lower DD&A in the first quarter of 2014 were mostly offset by lower net sales volumes due to lower mine reliability and nine days of planned mine maintenance.

Critical Accounting Estimates

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

Accounting Standards Not Yet Adopted

In April 2014, 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.

Cash Flows and Liquidity

Cash Flows

Net cash provided by continuing operations was $1,392 million in the first three months of 2014, compared to $1,503 million in the first three months of 2013. The $111 million decrease primarily reflects the impact of lower International E&P sales volumes on operating income.

Net cash provided by investing activities related to continuing operations was $1,097 million in the first three months of 2014, compared to net cash used of $983 million in the first three months of 2013. The increase in the first quarter of 2014 is primarily due to disposals of assets of $2,123 million, which reflects the net proceeds of the sales of our interests in Angola Blocks 31 and 32. In 2013, net proceeds of $312 million were primarily related to the sales of our Alaska assets and the Neptune gas plant.

Net cash used in financing activities related to continuing operations was $810 million in the first three months of 2014, compared to $413 million in the first three months of 2013. During the first three months of 2014, we repurchased $551 million of our common stock under our authorized share repurchase program. We repaid a net $135 million of commercial paper in the first three months of 2014 compared to $200 million in the first three months of 2013. Repayments of debt were $114 million in the first three months of 2013. Dividend payments were uses of cash in both periods.

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

At March 31, 2014, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

At March 31, 2014, we had $6,460 million in long-term debt outstanding, $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.

Shelf Registration

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

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 and cash equivalents) was 19 percent at March 31, 2014, compared to 25 percent at December 31, 2013.



	March 31,			December 31,
(In millions)	2014			2013
Commercial paper	$	—		$	135
Long-term debt due within one year	68			68
Long-term debt	6,392			6,394
Total debt	$	6,460		$	6,597
Cash and cash equivalents	$	1,964		$	264
Equity	$	19,805		$	19,344
Calculation:
Total debt	$	6,460		$	6,597
Minus cash and cash equivalents	1,964			264
Total debt minus cash	$	4,496		$	6,333
Total debt	$	6,460		$	6,597
Plus equity	19,805			19,344
Minus cash and cash equivalents	1,964			264
Total debt plus equity minus cash and cash equivalents	$	24,301		$	25,677
Cash-adjusted debt-to-capital ratio	19		%	25		%

Capital Requirements

On April 30, 2014, our Board of Directors approved a dividend of 19 cents per share for the first quarter of 2014, payable June 10, 2014 to stockholders of record at the close of business on May 21, 2014.

As of March 31, 2014, we plan to make contributions of up to $57 million to our funded pension plans during the remainder of 2014.

In 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized to $6.2 billion. As of March 31, 2014, we had repurchased 108 million common shares at a total cost of $4,273 million, with 16 million shares acquired at a cost of $551 million in the first quarter of 2014. In March of 2014, we began an additional $500 million share repurchase phase, which is substantially complete. Upon completion of this additional phase there will be $1.5 billion remaining on the Company's share repurchase authorization. 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 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 and natural gas, 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 March 31, 2014, our total contractual cash obligations were consistent with December 31, 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, 2013.

Other Contingencies

See Part II Item 1. Legal Proceedings for updated information about ongoing litigation.

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 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 11 and 12 to the consolidated financial statements.

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of March 31, 2014 is provided in the following table.



					Incremental
					Change in
(In millions)	Fair Value				Fair Value
Financial assets (liabilities): ^(a)
Interest rate swap agreements	$	7		^(b)	$	5
Long-term debt, including amounts due within one year	$	(7,020	)	^(b)(c)	$	(225	)


^(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 incremental change in fair value of our foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at March 31, 2014 would be $71 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 March 31, 2014.

During the first quarter of 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.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2014			2013
Segment Income (Loss)
North America E&P	$	242		$	(59	)
International E&P	331			454
Oil Sands Mining	64			38
Segment income	637			433
Items not allocated to segments, net of income taxes	(97		)	(53		)
Income from continuing operations	540			380
Discontinued operations ^(a)	609			3
Net income	$	1,149		$	383
Capital Expenditures ^(b)
North America E&P	$	867		$	970
International E&P	171			171
Oil Sands Mining	68			45
Corporate	3			30
Discontinued operations ^(a)	44			54
Total	$	1,153		$	1,270
Exploration Expenses
North America E&P	$	57		$	435
International E&P	19			28
Total	$	76		$	463


^(a)	In the first quarter of 2014, we closed the sale of our Angola assets. The Angola business is reflected as discontinued operations in all periods presented.


^(b)	Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Net Sales Volumes	2014	2013
North America E&P
Crude Oil and Condensate (mbbld)
Bakken	38	33
Eagle Ford	62	46
Oklahoma resource basins	2	1
Other North America	36	41
Total Crude Oil and Condensate	138	121
Natural Gas Liquids (mbbld)
Bakken	2	2
Eagle Ford	16	12
Oklahoma resource basins	4	4
Other North America	3	2
Total Natural Gas Liquids	25	20
Total Liquid Hydrocarbons (mbbld)
Bakken	40	35
Eagle Ford	78	58
Oklahoma resource basins	6	5
Other North America	39	43
Total Liquid Hydrocarbons	163	141
Natural Gas (mmcfd)
Bakken	16	13
Eagle Ford	107	83
Oklahoma resource basins	54	50
Alaska	0	31
Other North America	123	163
Total Natural Gas	300	340
Total North America E&P (mboed)	213	198

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Net Sales Volumes	2014	2013
International E&P
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	35	37
Norway	62	79
United Kingdom	13	21
Libya	0	34
Total Liquid Hydrocarbons	110	171
Natural Gas (mmcfd)
Equatorial Guinea	435	447
Norway	50	54
United Kingdom^(c)	30	41
Libya	3	26
Total Natural Gas	518	568
Total International E&P (mboed)	197	265
Oil Sands Mining
Synthetic Crude Oil (mbbld)^(d)	47	51
Total Continuing Operations (mboed)	457	514
Discontinued Operations (mboed)^(a)	6	9
Total Company (mboed)	463	523
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,579	6,787
Methanol (mtd)	1,153	1,410


^(c)	Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 11 mmcfd for the first quarters of 2014 and 2013.


^(d)	Includes blendstocks.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Average Price Realizations ^(e)	2014	2013
North America E&P
Crude Oil and Condensate (per bbl)
Bakken	$89.46	$91.22
Eagle Ford	96.10	103.78
Oklahoma resource basins	94.38	90.07
Other North America	89.25	87.30
Total Crude Oil and Condensate	92.48	94.68
Natural Gas Liquids (per bbl)
Bakken	$57.62	$41.05
Eagle Ford	37.50	28.16
Oklahoma resource basins	44.58	41.27
Other North America	61.83	56.58
Total Natural Gas Liquids	43.11	35.48
Total Liquid Hydrocarbons (per bbl) ^(f)
Bakken	$87.60	$88.60
Eagle Ford	84.16	88.06
Oklahoma resource basins	58.75	52.86
Other North America	87.40	85.41
Total Liquid Hydrocarbons	84.79	86.14
Natural Gas (per mcf)
Bakken	$8.41	$3.61
Eagle Ford	4.89	3.35
Oklahoma resource basins	5.50	3.56
Alaska	—	7.90
Other North America	5.10	3.49
Total Natural Gas	5.28	3.86


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


^(f)	Inclusion of realized losses on crude oil derivative instruments would have decreased average liquid hydrocarbon price realizations by $0.31 per bbl for the first three months of 2013. There were no crude oil derivative instruments for the first three months of 2014.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Average Price Realizations ^(e)	2014	2013
International E&P
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea	$62.37	$65.89
Norway	112.94	117.13
United Kingdom	109.53	112.25
Libya	—	129.56
Total Liquid Hydrocarbons	96.49	107.79
Natural Gas (per mcf)
Equatorial Guinea^(g)	$0.24	$0.24
Norway	12.01	14.00
United Kingdom	10.02	11.27
Libya	6.65	5.04
Total Natural Gas	1.98	2.57
Oil Sands Mining
Synthetic Crude Oil (per bbl)	$88.50	$79.98
Discontinued Operations (per bbl)^(a)	$99.82	$105.95

^(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

Environmental Proceedings

Based on currently available information, which is in many cases preliminary and incomplete, we believe as of March 31, 2014 that total clean-up and remediation costs connected with ongoing remediation sites will be approximately $25 million, the majority of which have already been incurred.

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 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 March 31, 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)
01/01/14 - 01/31/14	5,324	$35.03	—	$2,500,000,000
02/01/14 - 02/28/14	4,814,974	$33.30	4,803,356	$2,340,045,464
03/01/14 - 03/31/14	11,670,823	$33.76	11,576,645	$1,949,161,815
Total	16,491,121	$33.63	16,380,001


^(a)	83,556 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In March 2014, 27,564 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)	As of March 31, 2014, we had repurchased 108 million common shares at a cost of $4,273 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 16 million shares were acquired at a cost of $551 million during the first quarter of 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

10.1

Form of Performance Unit Award Agreement 2014 - 2016 Performance Cycle for Section 16 Officers

10.2

Form of Performance Unit Award Agreement 2014 - 2016 Performance Cycle for Officers

10.3

Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2012)

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2

Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

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.



May 7, 2014		MARATHON OIL CORPORATION

	By:	/s/ John R. Sult
		John R. Sult
		Executive Vice President and Chief Financial Officer

Exhibit Index

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

10.1

Form of Performance Unit Award Agreement 2014 - 2016 Performance Cycle for Section 16 Officers

10.2

Form of Performance Unit Award Agreement 2014 - 2016 Performance Cycle for Officers

10.3

Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2012)

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

31.2

Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.

32.1

Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2

Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.