MARATHON OIL CORP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - MARATHON OIL CORP	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - MARATHON OIL CORP	mro-20150331x10qxex321.htm
EX-31.1 - EXHIBIT 31.1 - MARATHON OIL CORP	mro-2015x0331x10qxex311.htm
EX-32.2 - EXHIBIT 32.2 - MARATHON OIL CORP	mro-2015x0331x10qxex322.htm
EX-10.1 - EXHIBIT 10.1 - MARATHON OIL CORP	mro-2015x0331x10qxex101.htm
EX-12.1 - EXHIBIT 12.1 - MARATHON OIL CORP	mro-2015x0331x10qxex121.htm
EX-31.2 - EXHIBIT 31.2 - MARATHON OIL CORP	mro-20150331x10qxex312.htm

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, 2015



[ ]	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 674,954,423 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2015.

MARATHON OIL CORPORATION

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



	Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
	Supplemental Statistics (Unaudited)	34
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 5.	Other Information	39
Item 6.	Exhibits	40
	Signatures	41

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)	2015			2014
Revenues and other income:
Sales and other operating revenues, including related party	$	1,280		$	2,149
Marketing revenues	204			541
Income from equity method investments	36			137
Net gain on disposal of assets	1			2
Other income	11			20
Total revenues and other income	1,532			2,849
Costs and expenses:
Production	444			542
Marketing, including purchases from related parties	205			542
Other operating	107			103
Exploration	90			73
Depreciation, depletion and amortization	821			643
Impairments	—			17
Taxes other than income	67			95
General and administrative	171			187
Total costs and expenses	1,905			2,202
Income (loss) from operations	(373		)	647
Net interest and other	(47		)	(49		)
Income (loss) from continuing operations before income taxes	(420		)	598
Provision (benefit) for income taxes	(144		)	200
Income (loss) from continuing operations	(276		)	398
Discontinued operations	—			751
Net income (loss)	$	(276	)	$	1,149
Per basic share:
Income (loss) from continuing operations	$	(0.41	)	$	0.58
Discontinued operations	$	—		$	1.08
Net income (loss)	$	(0.41	)	$	1.66
Per diluted share:
Income (loss) from continuing operations	$	(0.41	)	$	0.57
Discontinued operations	$	—		$	1.08
Net income (loss)	$	(0.41	)	$	1.65
Dividends per share	$	0.21		$	0.19
Weighted average common shares outstanding:
Basic	675			693
Diluted	675			696

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)	2015			2014
Net income (loss)	$	(276	)	$	1,149
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	76			(30		)
Income tax benefit (provision)	(27		)	10
Postretirement and postemployment plans, net of tax	49			(20		)
Comprehensive income (loss)	$	(227	)	$	1,129

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)	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	1,126		$	2,398
Receivables, less reserve of $4 and $3	1,341			1,729
Inventories	379			357
Other current assets	122			109
Total current assets	2,968			4,593
Equity method investments	1,100			1,113
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $22,648 and $21,884	29,291			29,040
Goodwill	459			459
Other noncurrent assets	918			806
Total assets	$	34,736		$	36,011
Liabilities
Current liabilities:
Accounts payable	$	1,854		$	2,545
Payroll and benefits payable	127			191
Accrued taxes	260			285
Other current liabilities	252			290
Long-term debt due within one year	1,068			1,068
Total current liabilities	3,561			4,379
Long-term debt	5,326			5,323
Deferred tax liabilities	2,437			2,486
Defined benefit postretirement plan obligations	515			598
Asset retirement obligations	1,949			1,917
Deferred credits and other liabilities	288			288
Total liabilities	14,076			14,991
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 95 million and 95 million shares	(3,634		)	(3,642		)
Additional paid-in capital	6,532			6,531
Retained earnings	17,220			17,638
Accumulated other comprehensive loss	(228		)	(277		)
Total stockholders' equity	20,660			21,020
Total liabilities and stockholders' equity	$	34,736		$	36,011

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)	2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(276	)	$	1,149
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(751		)
Deferred income taxes	(179		)	89
Depreciation, depletion and amortization	821			643
Impairments	—			17
Pension and other postretirement benefits, net	(7		)	19
Exploratory dry well costs and unproved property impairments	67			43
Net gain on disposal of assets	(1		)	(2		)
Equity method investments, net	3			(42		)
Changes in:
Current receivables	388			(69		)
Inventories	(22		)	(41		)
Current accounts payable and accrued liabilities	(469		)	33
All other operating, net	(16		)	(19		)
Net cash provided by continuing operations	309			1,069
Net cash provided by discontinued operations	—			401
Net cash provided by operating activities	309			1,470
Investing activities:
Additions to property, plant and equipment	(1,452		)	(1,004		)
Disposal of assets	2			2,123
Investments - return of capital	10			20
Investing activities of discontinued operations	—			(96		)
All other investing, net	(2		)	5
Net cash provided by (used in) investing activities	(1,442		)	1,048
Financing activities:
Commercial paper, net	—			(135		)
Purchases of common stock	—			(551		)
Dividends paid	(142		)	(133		)
All other financing, net	4			9
Net cash used in financing activities	(138		)	(810		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	(1		)	—
Discontinued operations	—			(8		)
Net increase (decrease) in cash and cash equivalents	(1,272		)	1,700
Cash and cash equivalents at beginning of period	2,398			264
Cash and cash equivalents at end of period	$	1,126		$	1,964

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 ("U.S. GAAP") for complete financial statements.

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

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2014 Annual Report on Form 10-K. The results of operations for the first quarter of 2015 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Not Yet Adopted

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

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

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

In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2017 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is not permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

Recently Adopted

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project ("AOSP"), in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $1 million recorded at March 31, 2015 and $3 million at December 31, 2014. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $506 million as of March 31, 2015. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.


4.	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 5 million stock options for the first three months of 2015 and 2014 that were antidilutive.



	Three Months Ended March 31,
(In millions, except per share data)	2015			2014
Income (loss) from continuing operations	$	(276	)	$	398
Discontinued operations	—			751
Net income (loss)	$	(276	)	$	1,149

Weighted average common shares outstanding	675			693
Effect of dilutive securities	—			3
Weighted average common shares, diluted	675			696
Per basic share:
Income (loss) from continuing operations	$	(0.41	)	$	0.58
Discontinued operations	$	—		$	1.08
Net income (loss)	$	(0.41	)	$	1.66
Per diluted share:
Income (loss) from continuing operations	$	(0.41	)	$	0.57
Discontinued operations	$	—		$	1.08
Net income (loss)	$	(0.41	)	$	1.65

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


5.	Dispositions

2014 - International E&P Segment

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

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



	Three Months Ended March 31,
(In millions)	2014
Revenues applicable to discontinued operations	$	680
Pretax income from discontinued operations	$	532
After-tax income from discontinued operations	$	142

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

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



	Three Months Ended March 31,
(In millions)	2014
Revenues applicable to discontinued operations	$	58
Pretax income from discontinued operations, before gain	$	51
Pretax gain on disposition of discontinued operations	$	470
After-tax income from discontinued operations	$	609

6. Segment Information

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


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


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


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

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

As discussed in Note 5, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the International E&P segment for 2014.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 2015
										Not Allocated
(In millions)	N.A. E&P			Int'l E&P			OSM			to Segments				Total
Sales and other operating revenues	$	850		$	182		$	225		$	23		^(c)	$	1,280
Marketing revenues	178			26			—			—				204
Total revenues	1,028			208			225			23				1,484
Income from equity method investments	—			36			—			—				36
Net gain on disposal of assets and other income	—			10			1			1				12
Less:
Production expenses	202			67			175			—				444
Marketing costs	180			25			—			—				205
Exploration expenses	35			55			—			—				90
Depreciation, depletion and amortization	683			64			62			12				821
Other expenses ^(a)	117			23			9			129			^(d)	278
Taxes other than income	61			—			5			1				67
Net interest and other	—			—			—			47				47
Income tax benefit	(89		)	(3		)	(6		)	(46		)		(144		)
Segment income (loss) /Income (loss) from continuing operations	$	(161	)	$	23		$	(19	)	$	(119	)		$	(276	)
Capital expenditures ^(b)	$	933		$	146		$	21		$	2			$	1,102


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


^(b)	Includes accruals.


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


^(d)	Includes $43 million of severance related expenses associated with a workforce reduction and a pension settlement loss of $17 million.



	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	$	380	$	377	$	—			$	2,149
Marketing revenues	440		70		31		—				541
Total revenues	1,832		450		408		—				2,690
Income from equity method investments	—		137		—		—				137
Net gain on disposal of assets and other income	3		17		2		—				22
Less:
Production expenses	211		100		231		—				542
Marketing costs	440		71		31		—				542
Exploration expenses	57		16		—		—				73
Depreciation, depletion and amortization	515		71		45		12				643
Impairments	17		—		—		—				17
Other expenses ^(a)	110		38		13		129			^(c)	290
Taxes other than income	90		—		5		—				95
Net interest and other	—		—		—		49				49
Income tax provision (benefit)	153		87		21		(61		)		200
Segment income/Income from continuing operations	$	242	$	221	$	64	$	(129	)		$	398
Capital expenditures ^(b)	$	867	$	105	$	68	$	3			$	1,043

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

(b)Includes accruals.

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

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)	2015			2014			2015			2014
Service cost	$	12		$	12		$	1		$	1
Interest cost	14			16			3			3
Expected return on plan assets	(19		)	(18		)	—			—
Amortization:
– prior service cost (credit)	1			1			(1		)	(1		)
– actuarial loss	7			6			—			—
Net settlement loss ^(a)	17			63			—			—
Net curtailment loss (gain)^(b)	1			—			(6		)	—
Net periodic benefit cost (credit)	$	33		$	80		$	(3	)	$	3


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


^(b)	Related to the workforce reduction, which reduced the future expected years of service for employees participating in the plans.

During the first quarter of 2015, we recorded the effects of a workforce reduction and a pension plan amendment. The pension plan amendment freezes the final average pay used to calculate the formula benefit and is effective July 6, 2015. Additionally, during the first quarter of 2015 and 2014, we recorded the effects of partial settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost (credit).

During the first three months of 2015, we made contributions of $23 million to our funded pension plans. We expect to make additional contributions up to an estimated $70 million to our funded pension plans over the remainder of 2015. During the first three months of 2015, we made payments of $12 million and $3 million related to unfunded pension plans and other postretirement benefit plans, respectively.

8. Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision (benefits) 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 2015 and 2014 were 34% and 33%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations would be 31% and 36% for the first three months of 2015 and 2014. In Libya, there remains uncertainty around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, for the first three months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).

9. Inventories

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



	March 31,		December 31,
(In millions)	2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	54	$	58
Supplies and other items	325		299
Inventories, at cost	$	379	$	357

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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



	March 31,		December 31,
(In millions)	2015		2014
North America E&P	$	16,954	$	16,717
International E&P	2,803		2,741
Oil Sands Mining	9,415		9,455
Corporate	119		127
Net property, plant and equipment	$	29,291	$	29,040

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

As of March 31, 2015, our net property, plant and equipment investment in Libya is $769 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 mmboe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continues to exceed the carrying value of $769 million by a material amount.

Exploratory well costs capitalized greater than one year after completion of drilling were $126 million as of March 31, 2015 and December 31, 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, 2015 and December 31, 2014 by fair value hierarchy level.



	March 31, 2015
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity	$	—	$	23	$	—	$	23
Interest rate	—		13		—		13
Derivative instruments, assets	$	—	$	36	$	—	$	36



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

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

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs.

See Note 12 for additional discussion of the types of derivative instruments we use.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Fair Values - Nonrecurring

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



	Three Months Ended March 31,
	2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	—	$	—	$	17

No impairments were recorded in the first three months of 2015. In the second half of 2014, commodity prices began a substantial decline which persisted into the first quarter of 2015. As this period of sustained reduced commodity prices continues, it could result in non-cash impairment charges related to long-lived assets in future periods.

The Ozona development in the Gulf of Mexico (held by our North America E&P segment) ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first quarter of 2014, we recorded an additional impairment of $17 million related to Ozona as a result of estimated abandonment cost revisions. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs.

Fair Values – Financial Instruments

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

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



	March 31, 2015				December 31, 2014
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	135	$	134	$	132	$	129
Total financial assets	135		134		132		129
Financial liabilities
Other current liabilities	13		13		13		13
Long-term debt, including current portion^(a)	6,980		6,361		6,887		6,360
Deferred credits and other liabilities	68		68		69		68
Total financial liabilities	$	7,061	$	6,442	$	6,969	$	6,441

^(a) Excludes capital leases.

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31, 2015 and December 31, 2014, there were no offsetting amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2015 and December 31, 2014.



	March 31, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	13	$	—	$	13	Other noncurrent assets
Total Designated Hedges	13		—		13

Not Designated as Hedges
Commodity	23		—		23		Other current assets
Total Not Designated as Hedges	23		—		23
Total	$	36	$	—	$	36



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

Derivatives Designated as Fair Value Hedges

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



	March 31, 2015				December 31, 2014
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.66	%	$	600	4.64	%
March 15, 2018	$	300	4.51	%	$	300	4.49	%

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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



		Gain (Loss)
			Three Months Ended March 31,
(In millions)	Income Statement Location		2015			2014
Derivative
Interest rate	Net interest and other		$	5		$	(1	)
Foreign currency	Discontinued operations		$	—		$	3
Hedged Item
Long-term debt	Net interest and other		$	(5	)	$	1
Accrued taxes	Discontinued operations		$	—		$	(3	)

Derivatives not Designated as Hedges

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



Three-Way Collars

Barrels per day	25,000
Index	NYMEX WTI
Weighted average price per barrel:
Ceiling	$71.67
Floor	$55.00
Sold put	$40.00
Remaining Term ^(a)	April - December 2015


^(a)	Counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price

of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If

counterparties exercise, the term of the fixed-price swaps would be for calendar year 2016 and, if all

such options are exercised, 25,000 barrels per day.

The impact of these commodity derivative instruments appears in sales and other operating revenues and was a net gain of $26 million in the first quarter of 2015. There were no commodity derivative instruments in the first quarter of 2014.

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 2015:



	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014	13,427,836				$29.68	3,448,353			$34.04
Granted	724,082		^(a)		$29.06	317,563			$28.93
Options Exercised/Stock Vested	(99,441	)			$17.36	(257,390	)		$34.94
Canceled	(272,031	)			$34.07	(414,431	)		$33.78
Outstanding at March 31, 2015	13,780,446				$29.65	3,094,095			$33.48

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

Stock-based performance unit awards

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

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

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



	Three Months Ended March 31,
(In millions)	2015			2014			Income Statement Line

Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(6	)	General and administrative
Net settlement loss	(17		)	(63		)	General and administrative
Net curtailment gain	5			—			General and administrative
	(19		)	(69		)	Income (loss) from operations
	7			23			Benefit for income taxes
Total reclassifications	$	(12	)	$	(46	)	Income (loss) from continuing operations

15. Supplemental Cash Flow Information



	Three Months Ended March 31,
(In millions)	2015			2014
Net cash provided by (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(55	)	$	(56	)
Income taxes paid to taxing authorities ^(a)	(47		)	(453		)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances	$	—		$	2,235
Repayments	—			(2,370		)
Commercial paper, net	—			(135		)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	21		$	37
Asset retirement obligations assumed by buyer	—			43
Receivable for disposal of assets	—			44


^(a)	Income taxes paid to taxing authorities included $357 million related to discontinued operations in the first three months of 2014 .

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

16. 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.

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


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


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


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

Executive Overview

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and their subsequent reinvestment into our business. The substantial decline in commodity prices that began in the second half of 2014 persisted through the first quarter of 2015. We believe we can manage in this lower commodity price cycle through a continued focus on development in our three U.S. resource plays, operational execution and efficiencies, and capital discipline, all while maintaining financial flexibility.

Our significant first quarter 2015 financial results and operating activities include the following:


•	Loss from continuing operations per diluted share of $(0.41) as compared to income from continuing operations of $0.57 per diluted share in the first quarter of 2014


•	Increased company-wide net sales volumes from continuing operations by 19% from 386 thousand barrels of oil equivalent per day ("mboed") in the first quarter of 2014 to 459 mboed


◦	Net sales volumes from our three U.S. resource plays increased 49% from 154 mboed in the first quarter of 2014 to 229 mboed


•	Achieved 98% average operational availability for our operated assets


•	Reduced North America E&P production expenses per boe by 28% compared to the first quarter of 2014


•	Completed our previously announced workforce reduction, incurring severance and related expenses of $43 million


•	Operating cash flow provided by continuing operations of $309 million, compared to $1.1 billion for first quarter of 2014


•	$3.6 billion of liquidity at the end of the first quarter, comprised of $1.1 billion in cash and $2.5 billion in the unused revolving credit facility; credit facility capacity increased to $3 billion after quarter end


•	Cash-adjusted debt-to-capital ratio of 20% at March 31, 2015, as compared with 16% at December 31, 2014

We continue to optimize our resource allocation and portfolio given the current price environment. We now expect our full-year 2015 capital, investment and exploration budget to be $3.3 billion, a decrease of $0.2 billion from our previously announced plan. We continue to estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 370 - 390 net mboed. We are targeting to generate at least $500 million from select non-core asset sales as we continue our ongoing portfolio management. See Cash Flows and Liquidity for further detail underlying our capital allocation.

Operations

North America E&P--Production

North America E&P segment average net sales volumes in the first quarter of 2015 increased 33% compared to the first quarter of 2014. Net liquid hydrocarbon sales volumes increased 60 thousand barrels per day ("mbbld") and net natural gas sales volumes increased 59 million cubic feet per day ("mmcfd") in the first quarter of 2015 compared to the first quarter of 2014, reflecting continued growth from the combined U.S. resource plays.



	Three Months Ended March 31,
	2015	2014
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Bakken	51	38
Eagle Ford	92	62
Oklahoma Resource Basins	5	2
Other North America ^(a)	36	36
Total Crude Oil and Condensate	184	138
Natural Gas Liquids (mbbld)
Bakken	3	2
Eagle Ford	27	16
Oklahoma Resource Basins	7	4
Other North America^(a)	2	3
Total Natural Gas Liquids	39	25
Total Liquid Hydrocarbons (mbbld)
Bakken	54	40
Eagle Ford	119	78
Oklahoma Resource Basins	12	6
Other North America^(a)	38	39
Total Liquid Hydrocarbons	223	163
Natural Gas (mmcfd)
Bakken	20	16
Eagle Ford	169	107
Oklahoma Resource Basins	78	54
Other North America^(a)	92	123
Total Natural Gas	359	300
Equivalent Barrels (mboed)
Bakken	57	43
Eagle Ford	147	96
Oklahoma Resource Basins	25	15
Other North America^(a)	54	59
Total North America E&P	283	213

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

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



	Three Months Ended March 31,
	2015	2014
Gross Operated
Eagle Ford:
Wells drilled to total depth	88	83
Wells brought to sales	91	49
Bakken:
Wells drilled to total depth	20	16
Wells brought to sales	24	15
Oklahoma Resource Basins:
Wells drilled to total depth	8	5
Wells brought to sales	5	4

Eagle Ford – Average net sales volumes from Eagle Ford were 147 mboed in the first quarter of 2015 compared to 96 mboed in the same period for 2014, for an increase of 53%. Approximately 63% of first quarter sales was crude oil and condensate, 18% was NGLs and 19% was natural gas. Our average time to drill an Eagle Ford well in first quarter 2015, spud-to-total depth, was 12 days. Our high-density pad drilling continues to average four wells per pad.

Included with the Eagle Ford well counts noted in the table above, we brought online nine gross operated Austin Chalk wells, compared to one in the same quarter of 2014. Twenty-four additional Austin Chalk wells are currently being drilled, completed or awaiting first production. We brought online our first four-well "stack-and-frac" pilot which included Austin Chalk, Upper Eagle Ford and two Lower Eagle Ford wells. Early performance from this pilot is encouraging.

Bakken – Average net sales volumes from the Bakken shale were 57 mboed in the first quarter of 2015 compared to 43 mboed in the same period for 2014, for an increase of 33%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 17 days in the first quarter of 2015.

The Bakken enhanced completion design pilot program has concluded with promising early results, which resulted in a revised standard well completion design for future wells. Data from the first 23 wells suggest greater than 30% improvement in cumulative production after 90 days when compared to direct offset performance. All 24 of the wells brought to sales in the first quarter incorporated an enhanced completion design, optimizing proppant loading, frac fluid volumes and stage density. Early performance of the first high-density pilot (six wells per horizon) is encouraging, and the second high-density spacing pilot recently started flowback. Additionally, we recently completed drilling our third high-density spacing pilot.

Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 25 mboed in the first quarter of 2015 compared to 15 mboed in the comparable 2014 period, for an increase of 67%. Approximately 48% of first quarter 2015 net production was liquids and 52% was natural gas. All five gross operated wells brought to sales this quarter were in the SCOOP with three of the wells in the southern SCOOP. We plan to maintain our program of two operated rigs in the Oklahoma Resource Basins.

Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 50 outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas. In the first quarter of 2015, we participated in five high-density outside-operated spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and two in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. The Woodford pilots include one high-density 10-well pilot comprised of five wells in the upper Woodford and five wells in the middle Woodford.

North America E&P--Exploration

Gulf of Mexico - We expect to spud the Solomon exploration prospect on Walker Ridge Block 225 in the second quarter of 2015. We currently hold a 78% operated working interest in the prospect, but are in advanced discussions to farm down our interest, and anticipate those discussions to be finalized in the second quarter of 2015.

International E&P--Production

International E&P segment average net sales volumes in the first quarter of 2015 decreased 8% compared to the first quarter of 2014, reflecting field decline and a planned turnaround at the AMPCO methanol facility completed in first quarter 2015.



	Three Months Ended March 31,
	2015	2014
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Equatorial Guinea	18	24
United Kingdom	13	12
Total Crude Oil and Condensate	31	36
Natural Gas Liquids (mbbld)
Equatorial Guinea	10	11
United Kingdom	—	1
Total Natural Gas Liquids	10	12
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	28	35
United Kingdom	13	13
Total Liquid Hydrocarbons	41	48
Natural Gas (mmcfd)
Equatorial Guinea	418	435
United Kingdom^(a)	33	30
Libya	—	3
Total Natural Gas	451	468
Equivalent Barrels (mboed)
Equatorial Guinea	97	108
United Kingdom^(a)	19	18
Total International E&P (mboed)	116	126
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,275	6,579
Methanol (mtd)	884	1,153


^(a)	Includes natural gas acquired for injection and subsequent resale of 10 mmcfd and 7 mmcfd for the first quarters of 2015 and 2014.

Equatorial Guinea – Average net sales volumes were 97 mboed in the first quarter of 2015 compared to 108 mboed in the same period of 2014 due to field decline and a planned turnaround completed in the first quarter of 2015 at the AMPCO methanol facility. In April, drilling commenced on the Alba C21 development well.

United Kingdom – Average net sales volumes were 19 mboed in the first quarter of 2015, relatively flat as compared to 18 mboed in the same period of 2014. Field decline was offset by the addition of South Brae infill wells brought online in late 2014 and first quarter of 2015, as well as the first of two subsea development wells at West Brae brought online in the first quarter 2015. Drilling was completed on a second West Brae well, which is expected to be online in the second quarter.

Libya – We had no sales in the first quarter of 2015 as a result of continued civil unrest. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.

International E&P--Exploration

Equatorial Guinea - Drilling and evaluation of the offshore Rodo-1 exploration well was completed in the first quarter of 2015. The well has been temporarily abandoned while further studies progress to evaluate commerciality of the light oil discovery.

Kurdistan Region of Iraq – On the operated Harir Block, the Mirawa-2 appraisal well was spud in December. Testing is in progress and is expected to be completed in the second quarter. We hold a 45% working interest in the block.

Oil Sands Mining

Our net synthetic crude oil sales volumes were 60 mbbld in the first quarter of 2015 compared to 47 mbbld in the same period of 2014. Higher net sales volumes, up 28% in the first quarter of 2015 compared to the year-ago quarter were primarily due to improved reliability. The Quest Carbon Capture and Storage project reached mechanical completion in February and is on schedule for fourth quarter 2015 start-up. A 55-day planned turnaround at the base upgrader began in April, coupled with a planned turnaround at the Muskeg River Mine, followed by an extended pitstop at the Jackpine Mine. We hold a 20% non-operated working interest in the AOSP.

Market Conditions

Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were significantly lower in the first three months of 2015 as compared to 2014; as a result, we experienced significant declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.

North America E&P

The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the first quarter of 2015 and 2014.



	Three Months Ended March 31,
	2015		2014
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)
Bakken		$39.92		$89.46
Eagle Ford	42.72		96.10
Oklahoma Resource Basins	45.57		94.38
Other North America ^(c)	41.39		89.25
Total Crude Oil and Condensate	41.75		92.48
Natural Gas Liquids (per bbl)
Bakken	N.M.			$57.62
Eagle Ford	13.73		37.50
Oklahoma Resource Basins	17.04		44.58
Other North America ^(c)	26.38		61.83
Total Natural Gas Liquids	14.43		43.11
Total Liquid Hydrocarbons (per bbl)
Bakken		$37.78		$87.60
Eagle Ford	36.30		84.16
Oklahoma Resource Basins	28.25		58.75
Other North America ^(c)	40.23		87.40
Total Liquid Hydrocarbons	36.92		84.79
Natural Gas (per mcf)
Bakken		$2.93		$8.41
Eagle Ford	2.88		4.89
Oklahoma Resource Basins	2.61		5.50
Other North America^(c)	3.59		5.10
Total Natural Gas	3.01		5.28
Benchmarks
WTI crude oil (per bbl)^(d)		$48.58		$98.62
Louisiana Light Sweet ("LLS") crude oil (per bbl)^(e)	52.84		104.38
Mont Belvieu NGLs (per bbl)^(f)	18.39		38.38
Henry Hub natural gas^(g) (per mmbtu)^(h)	2.98		4.94


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


^(b)	Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realization by $0.21 per bbl for the first quarter of 2015. There were no crude oil derivative instruments for the first quarter of 2014.


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


^(d)	NYMEX.


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


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


^(g)	Settlement date average.


^(h)	Million British thermal units.


N.M.	Not meaningful.

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

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

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

International E&P

The following table presents our average price realizations and the related benchmark for crude oil for the first quarter of 2015 and 2014.



	Three Months Ended March 31,
	2015		2014
Average Price Realizations
Crude Oil and Condensate (per bbl)
Equatorial Guinea	$42.55		$90.44
United Kingdom	57.19		110.99
Total Crude Oil and Condensate	48.87		97.73
Natural Gas Liquids (per bbl)
Equatorial Guinea ^(a)	$1.00		$1.00
United Kingdom	33.64		73.10
Total Natural Gas Liquids	3.46		4.52
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea		$27.85		$62.37
United Kingdom	55.81		109.53
Total Liquid Hydrocarbons	37.31		75.55
Natural Gas (per mcf)
Equatorial Guinea ^(a)		$0.24		$0.24
United Kingdom	7.68		10.02
Libya	—		6.65
Total Natural Gas	0.78		0.92
Benchmark
Brent (Europe) crude oil (per bbl)^(b)		$53.92		$108.17


^(a)	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.


^(b)	Average of monthly prices obtained from Energy Information Administration ("EIA") website.

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

NGLs in E.G. are subject to fixed-price, term contracts; therefore, our reported average NGL realized prices within the International E&P segment will not fully track market price movements.

Natural gas – Our natural gas sales from E.G. are subject to fixed-price, term contracts, making realized prices in this area less volatile; therefore, our reported average natural gas realized prices within the International E&P segment will not fully track market price movements.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS"). Comparing the corresponding 2015 and 2014 periods, the WCS discount to WTI narrowed in the first quarter of 2015 by $8.39 per barrel.

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 following table presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for the first quarter of 2015 and 2014.



	Three Months Ended March 31,
	2015		2014
Average Price Realizations
Synthetic Crude Oil (per bbl)		$40.37		$88.50
Benchmark
WTI crude oil (per bbl)^(a)		$48.58		$98.62
WCS crude oil (per bbl)^(b)	$33.90		$75.55
AECO natural gas sales index (per mmbtu)^(c)	$2.09		$4.99


^(a)	NYMEX.


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


^(c)	Monthly average AECO day ahead index.

Results of Operations

Consolidated Results of Operation

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



	Three Months Ended March 31,
(In millions)	2015		2014
Sales and other operating revenues, including related party
North America E&P	$	850	$	1,392
International E&P	182		380
Oil Sands Mining	225		377
Segment sales and other operating revenues, including related party	$	1,257	$	2,149
Unrealized gain on crude oil derivative instruments	23		—
Sales and other operating revenues, including related party	$	1,280	$	2,149

Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

North America E&P sales and other operating revenues decreased 39% in the first quarter of 2015 from the comparable 2014 period primarily due to lower price realizations, partially offset by higher net sales volumes from the U.S. resource plays. See additional detail by product in the table that follows:



	Three Months Ended		Increase (Decrease) Related to					Three Months Ended
(In millions)	March 31, 2014		Price Realizations			Net Sales Volumes		March 31, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	1,245	$	(960	)	$	456	$	741
Natural gas	142		(73		)	28		97
Realized gain on crude oil
derivative instruments	—		3					3
Other sales	5							9
Total	$	1,392						$	850

International E&P sales and other operating revenues decreased 52% in the first quarter of 2015 from the comparable 2014 period. The decrease was due to the lower price realizations and lower net sales volumes as detailed by product in the following table:



	Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	March 31, 2014		Price Realizations			Net Sales Volumes			March 31, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	330	$	(143	)	$	(48	)	$	139
Natural gas	38		(5		)	(1		)	32
Other sales	12								11
Total	$	380							$	182

Oil Sands Mining sales and other operating revenues decreased 40% in the first quarter of 2015, from the comparable 2014 period primarily due to lower synthetic crude oil price realizations, partially offset by higher net sales volumes. The following table displays changes by product:



	Three Months Ended		Increase (Decrease) Related to					Three Months Ended
(In millions)	March 31, 2014		Price Realizations			Net Sales Volumes		March 31, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	373	$	(260	)	$	104	$	217
Other sales	4							8
Total	$	377						$	225

Unrealized gains on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the first quarter of 2015, the net unrealized gain on crude oil derivative instruments was $23 million. There were no crude oil derivative instruments in the first quarter of 2014.

Marketing revenues decreased $337 million in the first quarter of 2015 from the comparable prior-year period. The decrease is related primarily to lower marketed volumes and the lower commodity price environment in North America. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Because the volume of marketing activity is based on market dynamics, it can fluctuate from period to period.

Income from equity method investments decreased $101 million in the first quarter of 2015 from the comparable 2014 period. The decrease in the first quarter of 2015 is primarily due to lower price realizations for Liquified Natural Gas ("LNG") at our LNG facility, Liquified Petroleum Gas ("LPG") at our Alba plant, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to this decrease in 2015 were lower sales volumes at the AMPCO methanol facility due to the previously mentioned turnaround.

Production expenses decreased $98 million in the first quarter of 2015 from the first quarter of 2014, primarily due to decreases of $56 million and $33 million in the OSM and International E&P segments, respectively. OSM production expenses decreased primarily as a result of lower feedstock costs and operating expenses, namely contract labor and utilities. International E&P production expenses decreased due to lower repair costs in the first quarter of 2015, versus the previous year which included costs related to reliability issues at the non-operated Foinaven field in the U.K. and non-recurring riser repairs in E.G.

The production expense rate (expense per boe) for North America E&P declined due to overall cost reductions and leveraging efficiencies in the first quarter of 2015 as production volumes increased. The expense rate for International E&P declined due to reduced project costs in 2015 as discussed in the preceding paragraph. The OSM expense rate declined as volumes increased while feedstock and operating expenses decreased. OSM utilized less feedstock (at lower prices) and experienced lower contract labor costs as a result of higher mine reliability in 2015. The following table provides production expense rates for each segment:



	Three Months Ended March 31,
($ per boe)	2015		2014
Production Expense Rate
North America E&P		$7.94		$11.02
International E&P		$6.40		$8.76
Oil Sands Mining ^(a)		$34.78		$47.54


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

Marketing costs decreased $337 million in the first quarter of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.

Exploration expenses were $17 million higher in the first quarter of 2015 than in the comparable 2014 period primarily due to higher dry well costs, partially offset by lower unproved property impairments. Dry well costs for the first quarter of 2015 include the Sodalita West #1 well in E.G. and the Key Largo well in the Gulf of Mexico, both of which were deemed unsuccessful in early 2015. The first quarter of 2014 included non-cash unproved property impairments related to Eagle Ford and Bakken leases that either had expired or that we did not expect to drill or extend. The following table summarizes the components of exploration expenses:



	Three Months Ended March 31,
(In millions)	2015		2014
Exploration Expenses
Unproved property impairments	$	9	$	41
Dry well costs	58		2
Geological and geophysical	3		11
Other	20		19
Total exploration expenses	$	90	$	73

Depreciation, depletion and amortization (“DD&A”) increased $178 million in the first quarter of 2015 from the comparable 2014 period primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays, partially offset by lower International E&P net sales volumes as previously discussed. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes sales volumes, reserves and capitalized costs, can also cause changes to our DD&A.



	Three Months Ended March 31,
($ per boe)	2015		2014
DD&A Rate
North America E&P		$26.85		$26.88
International E&P		$6.10		$6.25
Oil Sands Mining		$12.44		$11.70

Impairments are discussed in Note 11 to the consolidated financial statements.

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $28 million in the first quarter of 2015 from the comparable 2014 period. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:



	Three Months Ended March 31,
(In millions)	2015		2014
Production and severance	$	34	$	55
Ad valorem	16		19
Other	17		21
Total	$	67	$	95

General and administrative expenses decreased $16 million in the first quarter of 2015 primarily due to lower pension settlement expense of $17 million (compared to a $63 million settlement charge in the first quarter of 2014) and lower contract service expenses. This decrease was partially offset by $43 million of severance related expenses associated with a reduction in workforce in the first quarter of 2015.

Provision (benefit) for income taxes decreased $344 million in the first quarter of 2015 from the comparable 2014 period due to the change in income (loss) from continuing operations. See Note 8 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are net of tax. See Note 5 to the consolidated financial statements for financial information about discontinued operations.

Segment Income (Loss)

Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments. The following table reconciles segment income (loss) to net income (loss):



	Three Months Ended March 31,
(In millions)	2015			2014
North America E&P	$	(161	)	$	242
International E&P	23			221
Oil Sands Mining	(19		)	64
Segment income (loss)	(157		)	527
Items not allocated to segments, net of income taxes	(119		)	(129		)
Income (loss) from continuing operations	(276		)	398
Discontinued operations ^(a)	—			751
Net income (loss)	$	(276	)	$	1,149


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

North America E&P segment income (loss) decreased $403 million after-tax in the first quarter of 2015 from the comparable 2014 period. The decrease is primarily due to lower price realizations and higher DD&A, which was partially offset by the increased net sales volumes from the U.S. resource plays.

International E&P segment income decreased $198 million after-tax in the first quarter of 2015 from the comparable 2014 period. The decrease is primarily due to lower liquid hydrocarbon price realizations and net sales volumes, reduced income from equity investments in E.G., and higher exploration expenses. These decreases in first quarter 2015 segment income were partially offset by lower production expenses as first quarter 2014 included costs related to reliability issues at the non-operated Foinaven field in the U.K. and non-recurring riser repairs in E.G.

Oil Sands Mining segment income (loss) decreased $83 million after-tax in the first quarter of 2015 from the comparable 2014 period primarily due to lower price realizations, partially offset by higher net sales volumes and reduced production expenses. Lower production expenses pertained to lower feedstock costs and operating expenses, namely contract labor and utilities.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, 2014.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows and Liquidity

Cash Flows

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



	Three Months Ended March 31,
(In millions)	2015			2014
Sources of cash and cash equivalents
Continuing operations	$	309		$	1,069
Discontinued operations	—			401
Disposals of assets	2			2,123
Other	14			34
Total sources of cash and cash equivalents	$	325		$	3,627
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(1,452	)	$	(1,004	)
Investing activities of discontinued operations	—			(96		)
Purchases of common stock	—			(551		)
Commercial paper, net	—			(135		)
Dividends paid	(142		)	(133		)
Other	(3		)	(8		)
Total uses of cash and cash equivalents	$	(1,597	)	$	(1,927	)

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

Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposals of assets in the first three months of 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 5 to the consolidated financial statements.

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



	Three Months Ended March 31,
(In millions)	2015		2014
North America E&P	$	933	$	867
International E&P	146		105
Oil Sands Mining	21		68
Corporate	2		3
Total capital expenditures	1,102		1,043
(Increase) decrease in capital expenditure accrual	350		(39		)
Total use of cash and cash equivalents for property, plant and equipment	$	1,452	$	1,004

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

Liquidity and Capital Resources

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

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our $3 billion Credit Facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our revolving credit facility. Furthermore, we actively manage our capital spending program, including the level and timing of activities associated with our drilling programs. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our liquidity is adequate to fund not only our current operations, but also our funding requirements for the foreseeable future, including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

Outlook

We revised our capital, investment and exploration spending budget for full-year 2015 to $3.3 billion, down from $3.5 billion. Despite this reduction, our estimated full-year North America E&P and International E&P production volumes (excluding Libya) are expected to be 370-390 net mboed.

The budget reductions primarily impact the North America E&P segment and reflect reduced activity levels and more efficient and productive operations. Capital allocated to our three U.S. resource plays in 2015 has been reduced to $2.2 billion from $2.4 billion.


•	Eagle Ford capital reduced to $1.3 billion, reflecting a reduction to seven rigs by the end of the second quarter. We revised the number of gross operated wells to drill to sales to 227-247.


•	Bakken capital reduced to $645 million, reflecting a reduction to one rig by the end of the second quarter. The lower spend will fund the remaining downspacing pilots. We revised the number of gross operated wells to drill to sales to 53-63.


•	Oklahoma Resource Basins capital increased to $253 million, as a result of increased outside-operated activity. We plan to maintain a program of two operated rigs and participate in approximately 50 outside-operated wells in 2015. The number of gross operated wells to sales remains unchanged.

Capital Resources

Credit Arrangements and Borrowings

At March 31, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

At March 31, 2015, we had $6.4 billion in long-term debt outstanding. Approximately $1.1 billion is due within one year, most of which matures in the fourth quarter of 2015. 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 20% at March 31, 2015, compared to 16% at December 31, 2014.



	March 31,			December 31,
(In millions)	2015			2014
Long-term debt due within one year	$	1,068		$	1,068
Long-term debt	5,326			5,323
Total debt	$	6,394		$	6,391
Cash and cash equivalents	$	1,126		$	2,398
Equity	$	20,660		$	21,020
Calculation:
Total debt	$	6,394		$	6,391
Minus cash and cash equivalents	1,126			2,398
Total debt minus cash and cash equivalents	$	5,268		$	3,993
Total debt	$	6,394		$	6,391
Plus equity	20,660			21,020
Minus cash and cash equivalents	1,126			2,398
Total debt plus equity minus cash and cash equivalents	$	25,928		$	25,013
Cash-adjusted debt-to-capital ratio	20		%	16		%

Capital Requirements

We expect our capital spending to moderate over the remainder of 2015 as our total capital, investment and exploration spending budget for full-year 2015 is now projected to be $3.3 billion, a decrease of $0.2 billion from our previously announced plan. Additional details are discussed above in "Outlook." We continue to optimize our operations for efficiency improvements and to exercise capital discipline in this lower commodity price environment.

On April 29, 2015, our Board of Directors approved a dividend of $0.21 per share for the first quarter of 2015 payable June 10, 2015 to stockholders of record at the close of business on May 20, 2015.

As of March 31, 2015, we plan to make contributions of up to $70 million to our funded pension plans during the remainder of 2015.

Environmental Matters

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

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

Other Contingencies

Forward-Looking Statements

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


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


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


•	the amount of capital available for exploration and development;


•	timing of commencing production from new wells;


•	drilling rig availability;


•	availability of materials and labor;


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


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


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


•	cyber-attacks adversely affecting our operations;


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


•	other geological, operating and economic considerations; and


•	other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2014, and those set forth from time to time in our filings with the SEC.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2014 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 11 and 12 to the consolidated financial statements.

During the first quarter of 2015, we entered into crude oil derivatives related to a portion of our forecasted North America E&P sales which consisted of three-way collars with swaptions. The table below provides a summary of open positions as of March 31, 2015:



Crude Oil Derivative Positions
Three-way collars with swaptions
Barrels per day	25,000
Index	NYMEX WTI
Weighted average price per barrel:
Ceiling	$71.67
Floor	$55.00
Sold put	$40.00
Remaining Term ^(a)	April - December 2015


(a)	Counterparties have the option to exercise fixed-price swaps (swaptions) at a weighted average price

of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If the

counterparties exercise, the term of the fixed-price swaps would be for calendar year 2016 and, if all

such options are exercised, for 25,000 barrels per day.

The following table provides a sensitivity analysis of the projected incremental effect on income from operations ("IFO") of a hypothetical 10% change in NYMEX WTI prices on our open commodity derivative instruments as of March 31, 2015.

Subsequent to March 31, 2015, we entered into additional crude oil derivatives related to a portion of our forecasted North America E&P sales. These derivatives consist of three-way collars with sold call options and stand-alone three-way collars. The corresponding terms of these derivative positions entered into from April 1 through May 5, 2015 are shown in the table below:



Crude Oil Derivative Positions
Three-way collars
Barrels per day	10,000
Index	NYMEX WTI
Weighted average price per barrel:
Ceiling	$67.00
Floor	$57.00
Sold put	$44.50
Term ^(a)	April-December 2015
Three-way collars
Barrels per day	10,000
Index	NYMEX WTI
Weighted average price per barrel:
Ceiling	$71.81
Floor	$60.00
Sold put	$50.00
Term	January-December 2016

(a) Includes sold call options with weighted average price of $72.39 per barrel indexed to NYMEX WTI.

If executed, the term of the call options would be for calendar year 2016 and the same volume as the

underlying three-way collars.

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. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of March 31, 2015.

During the first quarter of 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2015			2014
Segment Income (Loss)
North America E&P	$	(161	)	$	242
International E&P	23			221
Oil Sands Mining	(19		)	64
Segment income (loss)	(157		)	527
Items not allocated to segments, net of income taxes	(119		)	(129		)
Income (loss) from continuing operations	(276		)	398
Discontinued operations ^(a)	—			751
Net income (loss)	$	(276	)	$	1,149
Capital Expenditures ^(b)
North America E&P	$	933		$	867
International E&P	146			105
Oil Sands Mining	21			68
Corporate	2			3
Discontinued operations ^(a)	—			110
Total	$	1,102		$	1,153
Exploration Expenses
North America E&P	$	35		$	57
International E&P	55			16
Total	$	90		$	73


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


^(b)	Includes accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Net Sales Volumes	2015	2014
North America E&P
Crude Oil and Condensate (mbbld)
Bakken	51	38
Eagle Ford	92	62
Oklahoma Resource Basins	5	2
Other North America ^(c)	36	36
Total Crude Oil and Condensate	184	138
Natural Gas Liquids (mbbld)
Bakken	3	2
Eagle Ford	27	16
Oklahoma Resource Basins	7	4
Other North America ^(c)	2	3
Total Natural Gas Liquids	39	25
Total Liquid Hydrocarbons (mbbld)
Bakken	54	40
Eagle Ford	119	78
Oklahoma Resource Basins	12	6
Other North America ^(c)	38	39
Total Liquid Hydrocarbons	223	163
Natural Gas (mmcfd)
Bakken	20	16
Eagle Ford	169	107
Oklahoma Resource Basins	78	54
Other North America ^(c)	92	123
Total Natural Gas	359	300
Equivalent Barrels (mboed)
Bakken	57	43
Eagle Ford	147	96
Oklahoma Resource Basins	25	15
Other North America ^(c)	54	59
Total North America E&P	283	213


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

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Net Sales Volumes	2015	2014
International E&P
Crude Oil and Condensate (mbbld)
Equatorial Guinea	18	24
United Kingdom	13	12
Total Crude Oil and Condensate	31	36
Natural Gas Liquids (mbbld)
Equatorial Guinea	10	11
United Kingdom	—	1
Total Natural Gas Liquids	10	12
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	28	35
United Kingdom	13	13
Total Liquid Hydrocarbons	41	48
Natural Gas (mmcfd)
Equatorial Guinea	418	435
United Kingdom ^(d)	33	30
Libya	—	3
Total Natural Gas	451	468
Equivalent Barrels (mboed)
Equatorial Guinea	97	108
United Kingdom ^(d)	19	18
Total International E&P	116	126
Oil Sands Mining
Synthetic Crude Oil (mbbld) ^(e)	60	47
Total Continuing Operations (mboed)	459	386
Discontinued Operations - Angola (mboed) ^(a)	—	6
Discontinued Operations - Norway (mboed) ^(a)	—	71
Total Company (mboed)	459	463
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,275	6,579
Methanol (mtd)	884	1,153


^(d)	Includes natural gas acquired for injection and subsequent resale of 10 mmcfd and 7 mmcfd for the first quarters of 2015 and 2014.


^(e)	Includes blendstocks.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Average Price Realizations ^(f)	2015	2014
North America E&P
Crude Oil and Condensate (per bbl) ^(g)
Bakken	$39.92	$89.46
Eagle Ford	42.72	96.10
Oklahoma Resource Basins	45.57	94.38
Other North America ^(c)	41.39	89.25
Total Crude Oil and Condensate	41.75	92.48
Natural Gas Liquids (per bbl)
Bakken	N.M.	$57.62
Eagle Ford	13.73	37.50
Oklahoma Resource Basins	17.04	44.58
Other North America ^(c)	26.38	61.83
Total Natural Gas Liquids	14.43	43.11
Total Liquid Hydrocarbons (per bbl)
Bakken	$37.78	$87.60
Eagle Ford	36.30	84.16
Oklahoma Resource Basins	28.25	58.75
Other North America ^(c)	40.23	87.40
Total Liquid Hydrocarbons	36.92	84.79
Natural Gas (per mcf)
Bakken	$2.93	$8.41
Eagle Ford	2.88	4.89
Oklahoma Resource Basins	2.61	5.50
Other North America^(c)	3.59	5.10
Total Natural Gas	3.01	5.28


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


^(g)	Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realizations by $0.21 per bbl for the first three months of 2015. There were no crude oil derivative instruments in 2014.


N.M.	Not meaningful.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
Average Price Realizations	2015	2014
International E&P
Crude Oil and Condensate (per bbl)
Equatorial Guinea	$42.55	$90.44
United Kingdom	57.19	110.99
Total Crude Oil and Condensate	48.87	97.73
Natural Gas Liquids (per bbl)
Equatorial Guinea ^(h)	$1.00	$1.00
United Kingdom	33.64	73.10
Total Natural Gas Liquids	3.46	4.25
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea	$27.85	$62.37
United Kingdom	55.81	109.53
Total Liquid Hydrocarbons	37.31	75.55
Natural Gas (per mcf)
Equatorial Guinea ^(h)	$0.24	$0.24
United Kingdom	7.68	10.02
Libya	—	6.65
Total Natural Gas	0.78	0.92
Oil Sands Mining
Synthetic Crude Oil (per bbl)	$40.37	$88.50
Discontinued Operations - Angola (per boe) ^(a)	—	99.82
Discontinued Operations - Norway (per boe) ^(a)	—	108.08


^(h)	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

Item 1A. Risk Factors

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

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

The following table provides information about purchases by Marathon Oil during the quarter ended March 31, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.



	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)(b)	Paid per Share	Plans or Programs	Plans or Programs
01/01/15 - 01/31/15	1,338	$28.33	—	$1,500,285,529
02/01/15 - 02/28/15	3,154	$28.06	—	$1,500,285,529
03/01/15 - 03/31/15	61,185	$27.52	—	$1,500,285,529
Total	65,677	$27.56	—


^(a)	65,677 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

Does not include shares 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. On March 9, 2015, the Dividend Reinvestment Plan was terminated. Participants in the Dividend Reinvestment Plan were transferred to Computershare CIP, a Direct Stock Purchase and Dividend Reinvestment Plan, which is sponsored and administered by Computershare Trust Company, N.A.

Item 5. Other Information

Amended and Restated By-laws

As we previously disclosed in a Form 8-K filed with the SEC on April 10, 2015, our Board of Directors amended and restated our By-laws, effective April 9, 2015, to implement “proxy access,” which allows eligible stockholders to include their own nominees for director in our proxy materials along with the Board-nominated candidates.

Pursuant to these amendments, a stockholder, or group of twenty or fewer stockholders (collectively, an “eligible stockholder”), meeting specified eligibility requirements, may include a director nominee in our proxy materials for our annual meetings of stockholders. To use these proxy access provisions, an eligible stockholder must, among other requirements:


•	have owned 5 % or more of our outstanding common stock continuously for at least three years; and


•	provide us with a notice requesting the inclusion of the director nominee in our proxy materials and other required information not less than 90 days nor more than 120 days prior to the first anniversary of the date on which we first mail our proxy materials for the preceding year’s annual meeting of stockholders.

All director nominees submitted through these provisions (“stockholder nominees”) must be independent and meet specified additional criteria. The maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions may not exceed 20% of the number of directors in office as of the last day on which notice requesting proxy access may be delivered by an eligible stockholder. In addition, an eligible stockholder may include a written statement of no more than 500 words supporting the candidacy of such stockholder nominee.

The proxy access process under the By-laws will first be available to stockholders in connection with our 2016 annual meeting of stockholders.

Amendment to Credit Agreement

On May 5, 2015, Marathon Oil Corporation entered into a First Amendment (the “Amendment”) to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein (the “Credit Agreement”).

The Amendment amends the Credit Agreement to, among other things, (i) increase the aggregate commitments by $500 million to an aggregate total amount of commitments of $3.0 billion, with an option to further increase the aggregate amount of commitments by up to an additional $500 million, subject to certain customary conditions, including obtaining the consent of any increasing lenders, and (ii) extend the maturity date by an additional year such that the Credit Agreement now matures on May 28, 2020, unless that date is extended under provisions in the Credit Agreement that allow us to request additional one-year extensions of the maturity date on up to two occasions. Any further extensions of the maturity date are subject to certain customary conditions, including the consent of lenders holding commitments representing a majority of the total commitments. If a Lender does not consent to an extension of the maturity date, then that Lender’s commitment will mature on the original maturity date of its commitment and will not be extended.

Certain lenders that are a party to the Amendment have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us and our subsidiaries, for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

The above description of the material terms and conditions of the Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Amendment, which is filed as an exhibit to this report.

Item 6. Exhibits

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

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, 2015		MARATHON OIL CORPORATION

	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

Exhibit Index



		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date
2.1++	Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	8-K	2.1	5/26/2011
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013
3.2	Amended By-Laws of Marathon Oil Corporation effective April 9, 2015	8-K	3.1	4/10/2015
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4.2	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request	10-K	4.2	2/28/2014
10.1	First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein*
12.1	Computation of Ratio of Earnings to Fixed Charges*
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS	XBRL Instance Document*
101.SCH	XBRL Taxonomy Extension Schema*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase*
101.DEF	XBRL Taxonomy Extension Definition Linkbase*
101.LAB	XBRL Taxonomy Extension Label Linkbase*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase*
*	Filed herewith.
++	Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

Incremental Change in IFO from a Hypothetical Price Increase of

Incremental Change in IFO from a Hypothetical Price Decrease of

(In millions)

Crude oil commodity derivatives