10-Q

10-Q 1 mro-20160331x10q.htm 10-Q 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, 2016



[ ]	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 847,648,273 shares of Marathon Oil Corporation common stock outstanding as of April 29, 2016.

MARATHON OIL CORPORATION

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

For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2015 Annual Report on Form 10-K.



	Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	31
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	32
	Signatures	33

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)	2016			2015
Revenues and other income:
Sales and other operating revenues, including related party	$	714		$	1,280
Marketing revenues	58			204
Income from equity method investments	14			36
Net gain (loss) on disposal of assets	(60		)	1
Other income	4			11
Total revenues and other income	730			1,532
Costs and expenses:
Production	328			444
Marketing, including purchases from related parties	58			205
Other operating	109			107
Exploration	24			90
Depreciation, depletion and amortization	609			821
Impairments	1			—
Taxes other than income	48			67
General and administrative	151			171
Total costs and expenses	1,328			1,905
Income (loss) from operations	(598		)	(373		)
Net interest and other	(85		)	(47		)
Income (loss) before income taxes	(683		)	(420		)
Provision (benefit) for income taxes	(276		)	(144		)
Net income (loss)	$	(407	)	$	(276	)
Net income (loss) per share:
Basic	$	(0.56	)	$	(0.41	)
Diluted	$	(0.56	)	$	(0.41	)
Dividends per share	$	0.05		$	0.21
Weighted average common shares outstanding:
Basic	730			675
Diluted	730			675

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)	2016			2015
Net income (loss)	$	(407	)	$	(276	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(24		)	76
Income tax provision (benefit)	9			(27		)
Postretirement and postemployment plans, net of tax	(15		)	49
Comprehensive income (loss)	$	(422	)	$	(227	)

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)	2016			2015
Assets
Current assets:
Cash and cash equivalents	$	2,072		$	1,221
Receivables, less reserve of $4 and $4	779			912
Inventories	306			313
Other current assets	111			144
Total current assets	3,268			2,590
Equity method investments	959			1,003
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $22,763 and $23,260	26,737			27,061
Goodwill	115			115
Other noncurrent assets	1,789			1,542
Total assets	$	32,868		$	32,311
Liabilities
Current liabilities:
Accounts payable	$	1,084		$	1,313
Payroll and benefits payable	79			133
Accrued taxes	151			132
Other current liabilities	211			150
Long-term debt due within one year	1			1
Total current liabilities	1,526			1,729
Long-term debt	7,280			7,276
Deferred tax liabilities	2,368			2,441
Defined benefit postretirement plan obligations	446			403
Asset retirement obligations	1,614			1,601
Deferred credits and other liabilities	283			308
Total liabilities	13,517			13,758
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 937 million shares and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	937			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 89 million and 93 million shares	(3,397		)	(3,554		)
Additional paid-in capital	7,428			6,498
Retained earnings	14,533			14,974
Accumulated other comprehensive loss	(150		)	(135		)
Total stockholders' equity	19,351			18,553
Total liabilities and stockholders' equity	$	32,868		$	32,311

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)	2016			2015
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(407	)	$	(276	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income taxes	(320		)	(179		)
Depreciation, depletion and amortization	609			821
Impairments	1			—
Pension and other postretirement benefits, net	14			(7		)
Exploratory dry well costs and unproved property impairments	11			67
Net (gain) loss on disposal of assets	60			(1		)
Equity method investments, net	30			3
Changes in:
Current receivables	133			388
Inventories	7			(22		)
Current accounts payable and accrued liabilities	(121		)	(469		)
All other operating, net	57			(16		)
Net cash provided by operating activities	74			309
Investing activities:
Additions to property, plant and equipment	(454		)	(1,452		)
Disposal of assets	17			2
Investments - return of capital	14			10
All other investing, net	2			(2		)
Net cash used in investing activities	(421		)	(1,442		)
Financing activities:
Common stock issuance	1,232			—
Dividends paid	(34		)	(142		)
All other financing, net	—			4
Net cash provided by (used in) financing activities	1,198			(138		)
Effect of exchange rate on cash and cash equivalents	—			(1		)
Net increase (decrease) in cash and cash equivalents	851			(1,272		)
Cash and cash equivalents at beginning of period	1,221			2,398
Cash and cash equivalents at end of period	$	2,072		$	1,126

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 SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2015 Annual Report on Form 10-K. The results of operations for the first quarter of 2016 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Not Yet Adopted

In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. 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 July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. 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 requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. 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 May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a retrospective basis. This standard only modifies disclosure requirements; as such, there was no 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 whether 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. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project, in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at March 31, 2016 and December 31, 2015. 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 $472 million as of March 31, 2016. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.


4.	Income (Loss) per Common Share

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



	Three Months Ended March 31,
(In millions, except per share data)	2016			2015
Net income (loss)	$	(407	)	$	(276	)

Weighted average common shares outstanding	730			675
Weighted average common shares, diluted	730			675
Net income (loss) per share:
Basic	$	(0.56	)	$	(0.41	)
Diluted	$	(0.56	)	$	(0.41	)


5.	Dispositions

North America E&P Segment

In April 2016, we entered into agreements to sell our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments. The upstream properties are comprised mainly of waterflood developments in the Big Horn and Wind River basins. The midstream assets include the 570-mile Red Butte pipeline. We expect the transaction to close mid-year 2016.

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments. The transactions are expected to close mid-year 2016.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

6. Segment Information

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


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


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


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

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



	Three Months Ended March 31, 2016
										Not Allocated
(In millions)	N.A. E&P			Int'l E&P			OSM			to Segments				Total
Sales and other operating revenues	$	493		$	96		$	148		$	(23	)	^(c)	$	714
Marketing revenues	31			15			12			—				58
Total revenues	524			111			160			(23		)		772
Income from equity method investments	—			14			—			—				14
Net gain (loss) on disposal of assets and other income	1			6			—			(63		)	^(d)	(56		)
Less:
Production expenses	134			53			141			—				328
Marketing costs	32			14			12			—				58
Exploration expenses	18			6			—			—				24
Depreciation, depletion and amortization	487			50			60			12				609
Impairments	1			—			—			—				1
Other expenses ^(a)	118			16			7			119			^(e)	260
Taxes other than income	42			—			5			1				48
Net interest and other	—			—			—			85				85
Income tax benefit	(112		)	(12		)	(17		)	(135		)		(276		)
Segment income (loss) / Net income (loss)	$	(195	)	$	4		$	(48	)	$	(168	)		$	(407	)
Capital expenditures ^(b)	$	315		$	32		$	9		$	3			$	359


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

(b)Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	Related to the net loss on disposal of assets (see Note 5).


^(e)	Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).

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) / Net income (loss)	$	(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 commodity derivative instruments.


^(d)	Includes $43 million of severance related expenses associated with a workforce reduction and pension settlement loss of $17 million (see Note 7).

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)	2016			2015			2016			2015
Service cost	$	6		$	12		$	1		$	1
Interest cost	11			14			3			3
Expected return on plan assets	(15		)	(19		)	—			—
Amortization:
– prior service cost (credit)	(2		)	1			(1		)	(1		)
– actuarial loss	3			7			—			—
Net settlement loss^(a)	48			17			—			—
Net curtailment loss (gain)^(b)	—			1			—			(6		)
Net periodic benefit cost	$	51		$	33		$	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 workforce reductions, which reduced the future expected years of service for employees participating in the plans.

During the first three months of 2016, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.

During the first three months of 2016, we made contributions of $14 million to our funded pension plans. We expect to make additional contributions up to an estimated $48 million to our funded pension plans over the remainder of 2016. During the first three months of 2016, we made payments of $19 million and $5 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

8. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision 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 for the first three months of 2016 and 2015 were 40% and 34%. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2016 and 2015 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, the tax benefit applicable to Libyan ordinary loss was recorded as a discrete item in the first three months of 2016 and 2015. For the first three months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates, would be 39% and 31% for the first three months of 2016 and 2015. The change was driven by a shift in jurisdictional income.

Deferred Tax Assets

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

9. Inventories

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



	March 31,		December 31,
(In millions)	2016		2015
Liquid hydrocarbons, natural gas and bitumen	$	33	$	35
Supplies and other items	273		278
Inventories, at cost	$	306	$	313

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



	March 31,		December 31,
(In millions)	2016		2015
North America E&P	$	14,953	$	15,226
International E&P	2,521		2,533
Oil Sands Mining	9,148		9,197
Corporate	115		105
Net property, plant and equipment	$	26,737	$	27,061

Our Libya operations continue to be impacted by civil unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Considerable uncertainty remains around the timing of future production and sales levels.

As of March 31, 2016, our net property, plant and equipment investment in Libya is $776 million, and total proved reserves (unaudited) in Libya as of December 31, 2015 are 235 million barrels of oil equivalent ("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 continue to exceed the carrying value of $776 million by a material amount.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Exploratory well costs capitalized greater than one year after completion of drilling were $120 million and $85 million as of March 31, 2016 and December 31, 2015. The $35 million increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the Alba Block Sub Area B exploration program.

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, 2016 and December 31, 2015 by fair value hierarchy level.



	March 31, 2016
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	51	$	—	$	51
Interest rate	—		12		—		12
Derivative instruments, assets	$	—	$	63	$	—	$	63
Derivative instruments, liabilities
Commodity^(a)	$	—	$	24	$	—	$	24
Derivative instruments, liabilities	$	—	$	24	$	—	$	24


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).



	December 31, 2015
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	51	$	—	$	51
Interest rate	$	—	$	8	$	—	$	8
Derivative instruments, assets	$	—	$	59	$	—	$	59
Derivative instruments, liabilities
Commodity^(a)	$	—	$	1	$	—	$	1
Derivative instruments, liabilities	$	—	$	1	$	—	$	1


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 12).

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

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 12 for additional discussion of the types of derivative instruments we use.

Fair Values – Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers for the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. A triggering event related to price declines in our common stock required us to reassess our goodwill

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future 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, 2016 and December 31, 2015.



	March 31, 2016				December 31, 2015
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	115	$	120	$	104	$	118
Total financial assets	$	115	$	120	$	104	$	118
Financial liabilities
Other current liabilities	$	34	$	33	$	34	$	33
Long-term debt, including current portion^(a)	6,575		7,291		6,723		7,291
Deferred credits and other liabilities	104		105		97		95
Total financial liabilities	$	6,713	$	7,429	$	6,854	$	7,419

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

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

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

12. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	March 31, 2016
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	12	$	—	$	12	Other noncurrent assets
Total Designated Hedges	$	12	$	—	$	12

Not Designated as Hedges
Commodity	$	51	$	7	$	44	Other current assets
Total Not Designated as Hedges	$	51	$	7	$	44
Total	$	63	$	7	$	56

	March 31, 2016
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	$	—	$	17	$	17	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	17	$	17
Total	$	—	$	17	$	17



	December 31, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Total Designated Hedges	$	8	$	—	$	8

Not Designated as Hedges
Commodity	$	51	$	1	$	50	Other current assets
Total Not Designated as Hedges	$	51	$	1	$	50
Total	$	59	$	1	$	58

Derivatives Designated as Fair Value Hedges

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



	March 31, 2016				December 31, 2015
	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	4.92	%	$	600	4.73	%
March 15, 2018	$	300	4.77	%	$	300	4.66	%

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. There is no ineffectiveness related to fair value hedges.



		Gain (Loss)
			Three Months Ended March 31,
(In millions)	Income Statement Location		2016			2015
Derivative
Interest rate	Net interest and other		$	4		$	5
Hedged Item
Long-term debt	Net interest and other		$	(4	)	$	(5	)

Derivatives not Designated as Hedges

During 2015 and the first quarter of 2016, we entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2017. These commodity derivatives consist of three-way collars, extendable three-way collars, call options, swaps, and swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and the weighted average prices for those contracts:



Crude Oil ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (Bbls/day)	39,000	37,000	37,000	—
Price per Bbl:
Ceiling	$55.47	$54.52	$54.52	—
Floor	$51.56	$50.83	$50.83	—
Sold put	$41.67	$41.22	$41.22	—
Options ^(c)
Volume (Bbls/day)	10,000	10,000	10,000	25,000
Price per Bbl	$72.39	$72.39	$72.39	$60.67
Swaps
Volume (Bbls/day)	25,000	—	—	—
Price per Bbl	$39.25	—	—	—

^(a)Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.


^(b)	A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.


^(c)	Call options settle monthly.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



Natural Gas ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (MMBtu/day)	20,000	20,000	20,000	20,000
Price per MMBtu
Ceiling	$2.93	$2.93	$2.93	$3.07
Floor	$2.50	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.00	$2.25


^(a)	Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.


^(b)	Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.

The impact of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net loss of $2 million and net gain of $26 million in the first quarters of 2016 and 2015, respectively.

13. Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first three months of 2016:



	Stock Options					Restricted Stock Awards & Units
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2015	12,665,419				$29.97	4,017,344			$30.76
Granted	1,680,000		^(a)		$7.22	5,230,708			$7.91
Options Exercised/Stock Vested	—			—		(44,096	)		$32.01
Canceled	(181,681	)			$29.69	(220,614	)		$30.00
Outstanding at March 31, 2016	14,163,738				$27.27	8,983,342			$17.47

^(a) The weighted average grant date fair value of stock option awards granted was $1.97 per share.

Stock-based performance unit awards

During the first three months of 2016, we granted 1,205,517 stock-based performance units to certain officers. The grant date fair value per unit was $3.72.

14. Debt

Revolving Credit Facility

As of March 31, 2016, we had no borrowings against our revolving credit facility (the "Credit Facility"), as described below.

In March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

the cash collateralization of all outstanding letters of credit under the Credit Facility. As of March 31, 2016, we were in compliance with this covenant with a debt-to-capitalization ratio of 27%.

15. Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:



	Three Months Ended March 31,
(In millions)	2016			2015			Income Statement Line

Postretirement and postemployment plans
Amortization of actuarial loss	$	(3	)	$	(7	)	General and administrative
Net settlement loss	(48		)	(17		)	General and administrative
Net curtailment gain (loss)	—			5			General and administrative
	(51		)	(19		)	Income (loss) from operations
	19			7			Provision (benefit) for income taxes
Total reclassifications to expense	$	(32	)	$	(12	)	Net income (loss)

16. Stockholder's Equity

In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.

17. Supplemental Cash Flow Information



	Three Months Ended March 31,
(In millions)	2016			2015
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(87	)	$	(55	)
Income taxes paid to taxing authorities	(15		)	(47		)
Noncash investing activities:
Asset retirement cost increase	$	2		$	21
Asset retirement obligations assumed by buyer	54			—

18. Commitments and Contingencies

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

19. Subsequent Event

In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining.

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

Results of Operations

Critical Accounting Estimates

Cash Flows and Liquidity

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

Executive Overview

We are an independent global exploration and production company based in Houston, Texas with operations in North America, Europe and Africa and a focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were $33 billion at March 31, 2016.

Our significant strategic actions and financial results include the following:


•	Continued to strengthen the balance sheet


◦	Raised net $1.2 billion from equity offering in the first quarter of 2016


◦	At the end of the first quarter of 2016, we had $5.4 billion of liquidity, comprised of $2.1 billion in cash and an undrawn $3.3 billion revolving credit facility


◦	Announced or closed $1.3 billion of non-core asset sales since August 2015, surpassing our target of $750 million to $1 billion. The largest component of this total was the $950 million non-core asset sales announced in April 2016 which consisted of:


▪	Wyoming upstream and midstream assets of $870 million, before closing adjustments


▪	Shenandoah discovery in the Gulf of Mexico (10% outside operated working interest); Piceance operated natural gas assets in Colorado; certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments


◦	Additions to property, plant and equipment, including accruals, of $359 million for the first quarter of 2016, down 67% compared to the year-ago quarter, reflecting continued capital discipline


◦	Executed additional commodity derivative instruments during the first quarter to reduce commodity price uncertainty for North America E&P crude oil and natural gas


◦	Reduced production expenses per boe in the first quarter of 2016 compared to the same period last year


▪	North America E&P - 22% reduction to $6.17 per boe


▪	Oil Sands Mining - 17% reduction to $28.80 per boe


◦	Cash-adjusted debt-to-capital ratio of 21% at March 31, 2016, as compared with 25% at December 31, 2015


•	Financial results


◦	Net loss per share of $0.56 in the first quarter of 2016 as compared to net loss per share of $0.41 in the same period last year

Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. We remain on track to achieve our objective of spending within our cash flows in 2016, inclusive of the non-core asset sales recently announced. We will continue to strengthen the balance sheet, evaluate our portfolio for strategic opportunities, adjust our Capital Program as necessary, and drive the fundamentals of expense management.

Exploration Update

Operations

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



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
North America E&P (mboed)	239	283	(16)%
International E&P (mboed)	96	116	(17)%
Oil Sands Mining (mbbld) ^(a)	59	60	(2)%
Total (mboed)	394	459	(14)%

^(a)Includes blendstocks

North America E&P

Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of decreased drilling and completion activity resulting in fewer wells brought to sales as well as 2015 dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma). The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	121	147	(18)%
Oklahoma Resource Basins	27	25	8%
Bakken	57	57	—
Other North America ^(a)	34	54	(37)%
Total North America E&P	239	283	(16)%

^(a)Includes Gulf of Mexico and other conventional onshore U.S. production, which was impacted by the sale of certain Gulf of Mexico assets in the fourth quarter of 2015.



	Three Months Ended March 31, 2016
Sales Mix - U.S. Resource Plays	Crude oil and condensate	Natural gas liquids	Natural gas

Eagle Ford	58%	21%	21%
Oklahoma Resource Basins	19%	26%	55%
Bakken	82%	11%	7%



	Three Months Ended March 31,
	2016	2015
Gross Operated
Eagle Ford:
Wells drilled to total depth	58	88
Wells brought to sales	50	91
Oklahoma Resource Basins:
Wells drilled to total depth	5	8
Wells brought to sales	3	5
Bakken:
Wells drilled to total depth	3	20
Wells brought to sales	6	24

•

Eagle Ford – Of the 50 gross operated wells brought to sales during the first quarter of 2016, 23 were Lower Eagle Ford, 19 were Upper Eagle Ford and 8 were Austin Chalk. Our average time to drill an Eagle Ford well in the first quarter 2016, spud-to-total depth, decreased to 8 days from 12 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,300 feet per day and the top-performing Eagle Ford rigs drilled four wells in excess of 3,300 feet per day.


•	Oklahoma Resource Basins – In the first quarter of 2016, we continued our focus on leasehold protection and delineation and brought 3 gross operated wells to sales, of which one was in the SCOOP Woodford, one in the SCOOP Springer and one in the STACK Meramec. We also participated in 7 outside-operated wells during the first quarter of 2016 that were focused in SCOOP and STACK.

•

Bakken – The 6 gross operated wells brought to sales in the first quarter of 2016 were in the greater Hector area, of which 4 were in Middle Bakken and 2 in Three Forks. Our average time to drill a Bakken well in the first quarter of 2016, spud-to-total depth, decreased to 12 days from 17 days in the first quarter of 2015. We released the remaining drilling rig in February and expect reduced completions activity during the second quarter.

•

Other North America – Net sales volumes declined in the first quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma. Additionally, development work continues in the Gunflint field located in Mississippi Canyon. First oil is expected in the second half of 2016 after the completion of work at a third party facility. We hold an 18% non-operated working interest in the Gunflint field.

International E&P

Net sales volumes in the segment were lower in the first quarter of 2016 primarily as a result of planned downtime in E.G. and repairs at Brae Alpha in the U.K. The following table provides details regarding net sales volumes for our significant operations within this segment.



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	84	97	(13)%
United Kingdom^(a)	12	19	(37)%
Total International E&P	96	116	(17)%
Equity Method Investees
LNG (mtd)	4,322	6,275	(31)%
Methanol (mtd)	1,280	884	45%
Condensate & LPG (boed)	10,208	13,223	(23)%


^(a)	Includes natural gas acquired for injection and subsequent resale of 5 mmcfd and 10 mmcfd for the first quarters of 2016 and 2015.

•

Equatorial Guinea – First quarter 2016 net sales were reduced compared to prior year quarter due to planned downtime associated with the installation of the Alba compression jacket and topsides, and planned maintenance activities in the onshore plants. This planned maintenance was successfully completed under budget and ahead of schedule. The ongoing Alba field compression project, designed to maintain the production plateau for an additional two years and extend field life up to eight years, remains on schedule with first production mid-year.


•	United Kingdom – Net sales volumes in first quarter 2016 were lower as a result of repairs at Brae Alpha which was shut-in throughout the quarter following a process pipe failure in late 2015, partially offset by improved reliability from the outside-operated Foinaven field. Full production from Brae Alpha resumed in late April.


•	Libya – Due to continued civil unrest, there were no liftings during the quarter. Considerable uncertainty remains around the timing of future production and sales levels.

Oil Sands Mining

Our net synthetic crude oil sales volumes were 59 mbbld first quarter of 2016 compared to 60 mbbld in the same period of 2015. Planned maintenance activities began ahead of schedule in mid-March at the base upgrader and the Jackpine mine which will impact production in the second quarter. In addition, in early May our operations at the Muskeg River and Jackpine mines have been suspended to support emergency response efforts related to the Fort McMurray area wildfires. The mines are approximately 60 miles north of the wildfires and not currently threatened by fire. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project.

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 lower in the first quarter of 2016 as compared to the same period in 2015; as a result, we experienced 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 2016 and 2015.



	Three Months Ended March 31,
	2016		2015		Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$28.21		$41.75		(32	)%
Natural Gas Liquids (per bbl)	8.12		14.43		(44	)%
Total Liquid Hydrocarbons (per bbl)	24.00		36.92		(35	)%
Natural Gas (per mcf)	2.02		3.01		(33	)%
Benchmarks
WTI crude oil (per bbl)		$33.63		$48.58	(31	)%
LLS crude oil (per bbl)	35.33		52.84		(33	)%
Mont Belvieu NGLs (per bbl)^(c)	13.95		18.39		(24	)%
Henry Hub natural gas (per mmbtu)	2.09		2.98		(30	)%


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


^(b)	Inclusion of realized gains on crude oil derivative instruments would have increased average realizations by $1.64 per bbl and $0.21 per bbl for the first quarter 2016 and 2015.


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

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

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

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

International E&P

The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the first quarter of 2016 and 2015.



	Three Months Ended March 31,
	2016		2015		Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$30.95		$48.87		(37	)%
Natural Gas Liquids (per bbl)	2.20		3.46		(36	)%
Liquid Hydrocarbons (per bbl)	22.66		37.31		(39	)%
Natural Gas (per mcf)	0.60		0.78		(23	)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)		$33.70		$53.92	(38	)%


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

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

Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are sold to our equity method investees under fixed-price, term contracts; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs and natural gas at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the Consolidated Statements of Income.

Oil Sands Mining

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

The following table presents our average price realizations and the related benchmarks for the first quarter of 2016 and 2015.



	Three Months Ended March 31,
	2016		2015		Increase (Decrease)
Average Price Realizations
Synthetic Crude Oil (per bbl)		$26.41		$40.37	(35	%)
Benchmarks
WTI crude oil (per bbl)		$33.63		$48.58	(31	%)
WCS crude oil (per bbl)^(a)	19.21		33.90		(43	%)


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

Results of Operations

Three Months Ended March 31, 2016 vs. Three Months Ended March 31, 2015

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



	Three Months Ended March 31,
(In millions)	2016			2015
Sales and other operating revenues, including related party
North America E&P	$	493		$	850
International E&P	96			182
Oil Sands Mining	148			225
Segment sales and other operating revenues, including related party	$	737		$	1,257
Unrealized (loss) gain on crude oil derivative instruments	(23		)	23
Sales and other operating revenues, including related party	$	714		$	1,280

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



	Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	March 31, 2015		Price Realizations			Net Sales Volumes			March 31, 2016
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	741	$	(220	)	$	(113	)	$	408
Natural gas	97		(29		)	(11		)	57
Realized gain on crude oil
derivative instruments	3		19						22
Other sales	9								6
Total	$	850							$	493
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	139	$	(43	)	$	(30	)	$	66
Natural gas	32		(6		)	(5		)	21
Other sales	11								9
Total	$	182							$	96
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	217	$	(74	)	$	—		$	143
Other sales	8								5
Total	$	225							$	148

Marketing revenues decreased $146 million in the first quarter of 2016 from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.

Income from equity method investments decreased $22 million in the first quarter of 2016 from the comparable 2015 period. The decrease is primarily due to lower net sales volumes as a result of planned downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants. Also impacting the quarter were lower price realizations for LPG at our Alba plant and lower methanol prices at our AMPCO methanol facility.

Net loss on disposal of assets in the first quarter of 2016 was related to the sale of non-core assets. See Note 5 to the consolidated financial statements for information about dispositions.

Production expenses decreased $116 million. North America E&P declined $68 million primarily due to lower operational, maintenance and labor costs, coupled with the 2015 disposition of certain producing Gulf of Mexico assets. International E&P declined $14 million primarily as a result of lower operational costs in Libya and lower costs in the U.K. associated with lower net sales volumes, which was offset by higher planned maintenance costs in E.G. during the first quarter of 2016. OSM decreased $34 million primarily due to a more favorable exchange rate on expenses denominated in the Canadian Dollar and continued cost management, especially staffing and contract labor.

The first quarter of 2016 production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in Libya. The OSM expense rate decreased due to the positive currency effects and the increased cost focus, as discussed above.

The following table provides production expense rates for each segment:



	Three Months Ended March 31,
($ per boe)	2016		2015
Production Expense Rate
North America E&P		$6.17		$7.94
International E&P		$6.08		$6.40
Oil Sands Mining ^(a)		$28.80		$34.78


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

Marketing costs decreased $147 million in the first quarter of 2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.

Exploration expenses decreased $66 million primarily due to higher dry well costs in the first quarter of 2015 which included the Sodalita West #1 well in E.G. and the Key Largo well in the Gulf of Mexico. The following table summarizes the components of exploration expenses:



	Three Months Ended March 31,
(In millions)	2016		2015
Exploration Expenses
Unproved property impairments	$	11	$	9
Dry well costs	—		58
Geological and geophysical	—		3
Other	13		20
Total exploration expenses	$	24	$	90

Depreciation, depletion and amortization decreased $212 million primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford and as a result of the Gulf of Mexico disposition in 2015 discussed above. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford.



	Three Months Ended March 31,
($ per boe)	2016		2015
DD&A Rate
North America E&P		$22.39		$26.85
International E&P		$5.68		$6.10
Oil Sands Mining		$11.30		$12.44

Taxes other than income decreased $19 million in the first quarter of 2016. The following table summarizes the components of taxes other than income:



	Three Months Ended March 31,
(In millions)	2016		2015
Production and severance	$	19	$	34
Ad valorem	13		16
Other	16		17
Total	$	48	$	67

General and administrative expenses decreased $20 million primarily due to cost savings realized from the workforce reductions in 2015, as well as lower severance related expenses in the current year. This was partially offset by pension settlement charges in the first three months of 2016 which totaled $48 million compared to $17 million in the prior year.

Net interest and other increased $38 million primarily due to higher net foreign currency loss and increased interest expense associated with our June 2015 debt issuance.

Provision (benefit) for income taxes reflects an effective tax rate of 40% in the first quarter of 2016, as compared to 34% in the first quarter of 2015. See Note 8 to the consolidated financial statements for discussion of the effective tax rate.

Segment Income (Loss)

Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, 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)	2016			2015
North America E&P	$	(195	)	$	(161	)
International E&P	4			23
Oil Sands Mining	(48		)	(19		)
Segment income (loss)	(239		)	(157		)
Items not allocated to segments, net of income taxes	(168		)	(119		)
Net income (loss)	$	(407	)	$	(276	)

North America E&P segment loss increased $34 million after-tax primarily due to lower price realizations and sales volumes, which was partially offset by lower DD&A and production expenses.

International E&P segment income decreased $19 million after-tax primarily due to lower price realizations and sales volumes as well as reduced income from equity investments. These declines were partially offset by lower exploration, production and DD&A expenses.

Oil Sands Mining segment loss increased $29 million after-tax primarily due to lower price realizations, partially offset by lower production expenses.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2015, except as discussed below.

Fair Value Estimates - Goodwill

Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. A triggering event related to price declines in our common stock required us to reassess our goodwill for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Estimated Quantities of Net Reserves

Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first four months of 2016:



	Unweighted 12-month 2015 Average	Unweighted 4-month 2016 Average
WTI Crude oil	$50.28	$35.67
Henry Hub natural gas	2.59	2.00
Brent crude oil	54.25	35.95
Natural gas liquids	17.32	13.16

Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices remain at lower levels throughout 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. If prices remain at the 4-month average depicted above throughout 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. Assuming lower SEC pricing in 2016, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows

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



	Three Months Ended March 31,
(In millions)	2016			2015
Sources of cash and cash equivalents
Operating activities	$	74		$	309
Common stock issuance	1,232			—
Disposals of assets	17			2
Other	16			14
Total sources of cash and cash equivalents	$	1,339		$	325
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(454	)	$	(1,452	)
Dividends paid	(34		)	(142		)
Other	—			(3		)
Total uses of cash and cash equivalents	$	(488	)	$	(1,597	)

Cash flows generated from operating activities in the first quarter of 2016 were lower as the downturn in the commodity cycle continued. This continued downward pressure on price realizations, coupled with the lower net sales volumes, continues to negatively impact our cash flows from operating activities. In the first quarter of 2016, consolidated average liquids price realizations were down by approximately 35% and consolidated net sales volumes declined by 14% as compared to the prior year quarter.

Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Liquidity and Capital Resources below for additional information.

Additions to property, plant and equipment are our most significant use of cash and cash equivalents. Total capital expenditures, including accruals, were 67% lower in the first quarter of 2016 consistent with a reduced Capital Program as compared to the prior year. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:



	Three Months Ended March 31,
(In millions)	2016		2015
North America E&P	$	315	$	933
International E&P	32		146
Oil Sands Mining	9		21
Corporate	3		2
Total capital expenditures	359		1,102
Decrease in capital expenditure accrual	95		350
Total use of cash and cash equivalents for property, plant and equipment	$	454	$	1,452

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

Liquidity and Capital Resources

Also in March 2016, we increased our $3.0 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.

Our main sources of liquidity are cash and cash equivalents, sales of non-core assets, internally generated cash flow from operations, capital market transactions, and our $3.3 billion Credit Facility. Our working capital requirements are supported by these sources and we may draw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

Due to decreases in crude oil and U.S. natural gas prices earlier this year, credit rating agencies recently reviewed many companies in the industry, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

At March 31, 2016, we had no borrowings against our revolving credit facility.

At March 31, 2016, we had $7.3 billion in long-term debt outstanding, with our next debt maturity in the amount of $680 million due in the fourth quarter of 2017.

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

Shelf Registration

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

Asset Disposals

Since August 2015, we have announced or closed non-core asset sales of approximately $1.3 billion, surpassing our targeted range of $750 million to $1 billion. In the largest transaction, we will divest all of our Wyoming upstream and midstream assets for $870 million, before closing adjustments, with closing expected mid-year 2016. In separate transactions, we signed agreements for the sale of our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments, with closing expected mid-year 2016.

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 21% at March 31, 2016, compared to 25% at December 31, 2015.



	March 31,			December 31,
(In millions)	2016			2015
Long-term debt due within one year	$	1		$	1
Long-term debt	7,280			7,276
Total debt	$	7,281		$	7,277
Cash and cash equivalents	$	2,072		$	1,221
Equity	$	19,351		$	18,553
Calculation:
Total debt	$	7,281		$	7,277
Minus cash and cash equivalents	2,072			1,221
Total debt minus cash, cash equivalents	$	5,209		$	6,056
Total debt	$	7,281		$	7,277
Plus equity	19,351			18,553
Minus cash and cash equivalents	2,072			1,221
Total debt plus equity minus cash, cash equivalents	$	24,560		$	24,609
Cash-adjusted debt-to-capital ratio	21		%	25		%

Capital Requirements

Our Board of Directors approved a Capital Program of $1.4 billion for 2016.

On April 27, 2016, our Board of Directors approved a dividend of $0.05 per share for the first quarter of 2016 payable June 10, 2016 to stockholders of record at the close of business on May 18, 2016.

As of March 31, 2016, we plan to make contributions of up to $48 million to our funded pension plans during the remainder of 2016.

Contractual Cash Obligations

As of March 31, 2016, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2015 Annual Report on Form 10-K.

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, 2015.

Other Contingencies

Forward-Looking Statements

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


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


•	changes in expected reserve or production levels;


•	changes in political or economic conditions in the jurisdictions in which we operate;


•	capital available for exploration and development;


•	well production timing;


•	availability of drilling rigs, materials and labor;


•	difficulty in obtaining necessary approvals and permits;


•	non-performance by third parties of contractual obligations;


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


•	cyber-attacks;


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


•	other geological, operating and economic considerations; and


•	the risk factors, forward-looking statements and challenges and uncertainties described in our 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty or obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

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 2015 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.

Commodity Price Risk During the first three months of 2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The following tables provide a summary of open positions as of March 31, 2016 and the weighted average price for those contracts:



Crude Oil ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (Bbls/day)	39,000	37,000	37,000	—
Price per Bbl
Ceiling	$55.47	$54.52	$54.52	—
Floor	$51.56	$50.83	$50.83	—
Sold put	$41.67	$41.22	$41.22	—
Options ^(c)
Volume (Bbls/day)	10,000	10,000	10,000	25,000
Price per Bbl	$72.39	$72.39	$72.39	$60.67
Swaps
Volume (Bbls/day)	25,000	—	—	—
Price per Bbl	$39.25	—	—	—


^(b)	A counterparty has the option, exercisable on June 30, 2016, to extend three-way collars for 2,000 Bbls/day through the remainder of 2016 at a ceiling of $73.13, floor of $65.00 and sold put of $50.00.


^(c)	Call options settle monthly.



Natural Gas ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (MMBtu/day)	20,000	20,000	20,000	20,000
Price per MMBtu
Ceiling	$2.93	$2.93	$2.93	$3.07
Floor	$2.50	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.00	$2.25


^(a)	Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.


^(b)	Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of March 31, 2016.



(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%

Crude oil derivatives	$	(46	)	$	38
Natural gas derivatives	(3		)	3
Total	$	(49	)	$	41

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on financial assets and liabilities as of March 31, 2016, is provided in the following table.



(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities): ^(a)
Interest rate swap agreements	$	12		^(b)	$	1
Long term debt, including amounts due within one year	$	(6,575	)	^(b)(c)	$	(310	)


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


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


^(c)	Excludes capital leases.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of March 31, 2016.

During the first quarter of 2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II – OTHER INFORMATION

Item 1. Legal and Administrative 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 2015 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, 2016, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.



	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)	Paid per Share	Plans or Programs	Plans or Programs
01/01/16 - 01/31/16	4,032	$12.96	—	n/a
02/01/16 - 02/29/16	7,402	$8.01	—	n/a
03/01/16 - 03/31/16	290	$7.82	—	n/a
Total	11,724	$9.71	—


^(a)	11,724 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Exhibit Index accompanying this 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 5, 2016		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
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013
3.2	Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)	8-K	3.1	3/1/2016
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4.1	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request	10-K	4.1	2/28/2014
12.1	Computation of Ratio of Earnings to Fixed Charges*
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS	XBRL Instance Document*
101.SCH	XBRL Taxonomy Extension Schema*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase*
101.DEF	XBRL Taxonomy Extension Definition Linkbase*
101.LAB	XBRL Taxonomy Extension Label Linkbase*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase*
*	Filed herewith.