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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 2019 Annual Report on Form 10-K. The results of operations for the first quarter of 2020 are not necessarily indicative of the results to be expected for the full year.

Recently Adopted

Financial instruments – credit losses    

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. On January 1, 2020 we adopted this standard using the modified retrospective transition method through a cumulative-effect adjustment of $12 million to retained earnings as of the beginning of the adoption period. The standard requires the use of a forward-looking “expected loss” model as opposed to the “incurred loss” model used previously. See Note 8 for more information on credit losses.

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 in all periods, provided the effect is not antidilutive. The per share calculations below exclude 6 million and 5 million of stock options for the three months ended March 31, 2020 and 2019 that were antidilutive.

	Three Months Ended March 31,
(In millions, except per share data)	2020				2019
Net income (loss)	$	(46	)		$	174
Weighted average common shares outstanding	794				819
Effect of dilutive securities	—				1
Weighted average common shares, diluted	794				820
Net income (loss) per share:
Basic	$	(0.06	)		$	0.21
Diluted	$	(0.06	)		$	0.21
Dividends per share	$	0.05			$	0.05

International Segment

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The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and term agreements with our customers in the United States and various international locations.

As of March 31, 2020 and December 31, 2019, receivables from contracts with customers, included in receivables, less reserves were $477 million and $837 million, respectively.

The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas for the three months ended March 31 as follows:

United States

	March 31, 2020
(In millions)	Eagle Ford				Bakken				Oklahoma				Northern Delaware				Other U.S.				Total
Crude oil and condensate	$	307			$	330			$	84			$	74			$	33			$	828
Natural gas liquids	16				10				21				3				2				52
Natural gas	23				8				29				3				3				66
Other	2				—				—				—				22				24
Revenues from contracts with customers	$	348			$	348			$	134			$	80			$	60			$	970

	March 31, 2019
(In millions)	Eagle Ford				Bakken				Oklahoma				Northern Delaware				Other U.S.				Total
Crude oil and condensate	$	318			$	372			$	77			$	64			$	28			$	859
Natural gas liquids	35				10				22				8				2				77
Natural gas	34				12				45				6				6				103
Other	2				—				—				—				21				23
Revenues from contracts with customers	$	389			$	394			$	144			$	78			$	57			$	1,062

International

	March 31, 2020
(In millions)	E.G.
Crude oil and condensate	$	45
Natural gas liquids	1
Natural gas	8
Revenues from contracts with customers	$	54

	March 31, 2019
(In millions)	E.G.				U.K.				Other Int’l				Total
Crude oil and condensate	$	47			$	56			$	10			$	113
Natural gas liquids	1				1				—				2
Natural gas	7				8				—				15
Other	—				8				—				8
Revenues from contracts with customers	$	55			$	73			$	10			$	138

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We have two reportable operating segments. Both of these segments are organized and managed based upon geographic location and the nature of the products and services offered.

•	United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

•	International (“Int’l”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea (“E.G.”)

Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support 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. Additionally, items which affect comparability such as: gains or losses on dispositions, certain property and goodwill impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the chief operating decision maker (“CODM”)) are not allocated to operating segments.

	Three Months Ended March 31, 2020
(In millions)	U.S.				Int’l				Not Allocated to Segments				Total
Revenues from contracts with customers	$	970			$	54			$	—			$	1,024
Net gain (loss) on commodity derivatives	31				—				171			(b)	202
Income (loss) from equity method investments	—				(12		)		—				(12		)
Net gain on disposal of assets	—				—				9				9
Other income	4				2				1				7
Less costs and expenses:
Production	143				17				—				160
Shipping, handling and other operating	140				3				1				144
Exploration	28				—				—				28
Depreciation, depletion and amortization	617				21				6				644
Impairments	—				—				97			(c)	97
Taxes other than income	66				—				—				66
General and administrative	32				4				40				76
Net interest and other	—				—				64				64
Other net periodic benefit costs	—				—				—				—
Income tax benefit	(1		)		—				(2		)		(3		)
Segment loss	$	(20	)		$	(1	)		$	(25	)		$	(46	)
Total assets	$	17,453			$	1,405			$	857			$	19,715
Capital expenditures(a)	$	561			$	—			$	7			$	568

(a)	Includes accruals.

(b)	Unrealized gain on commodity derivative instruments (See Note 15).

(c)	Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 14).

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	Three Months Ended March 31, 2019
(In millions)	U.S.				Int’l				Not Allocated to Segments				Total
Revenues from contracts with customers	$	1,062			$	138			$	—			$	1,200
Net gain (loss) on commodity derivatives	22				—				(113		)	(b)	(91		)
Income from equity method investments	—				11				—				11
Net gain on disposal of assets	—				—				42			(c)	42
Other income	1				3				31			(d)	35
Less costs and expenses:
Production	139				50				(2		)		187
Shipping, handling and other operating	140				13				1				154
Exploration	59				—				—				59
Depreciation, depletion and amortization	514				34				6				554
Impairments	—				—				6			(e)	6
Taxes other than income	74				—				(2		)		72
General and administrative	29				7				58				94
Net interest and other	—				—				49				49
Other net periodic benefit costs	—				(2		)		(3		)		(5		)
Income tax benefit	(2		)		(11		)		(134		)	(f)	(147		)
Segment income (loss)	$	132			$	61			$	(19	)		$	174
Total assets	$	17,503			$	2,668			$	1,239			$	21,410
Capital expenditures(a)	$	606			$	5			$	3			$	614

(a)	Includes accruals.

(b)	Unrealized loss on commodity derivative instruments (See Note 15).

(c)	Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico), which closed during the first quarter of 2019.

(d)	Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit with the IRS (See Note 7).

(e)	Due to the anticipated sale of non-operated interest in the Atrush block in Kurdistan (See Note 11).

(f)	Primarily relates to the settlement of the 2010-2011 Federal Tax Audit (See Note 7).

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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.

For the three months ended March 31, 2020 and 2019, our effective income tax rates were as follows:

	Three Months Ended March 31,
	2020			2019
Effective income tax rate(a)	6	%		(544	)%

(a)	In all periods presented, we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

The following items caused the effective income tax rates to be different from our U.S. statutory tax rate of 21% for 2020 and 2019:

•	Income taxes for the first quarter of 2020 were impacted by the income mix within E.G. between equity method investees and subsidiaries, which reduces the annual effective tax rate below the statutory tax rate.

•

Income taxes for the three months ended March 31, 2019 were impacted by the settlement of the 2010-2011 U.S. Federal Tax Audit (“IRS Audit”) in the first quarter of 2019, resulting in a tax benefit of $126 million. Additionally, in the first quarter of 2019, we recorded a non-cash deferred tax benefit of $18 million in the U.K. related to an internal restructuring. These two items are discrete to the first quarter of 2019. Excluding these discrete adjustments, the effective income tax rate for the first quarter of 2019 was an expense of 8%.

On March 27, 2020, the U.S. enacted the Coronavirus Aid, Relief, and Economic Security Act, commonly referred to as the CARES Act.  This legislation included certain provisions which accelerate income tax refunds, and as a result, in the first quarter of 2020, long term receivable balances related to alternative minimum tax credits have been reclassified as short term. We expect to receive cash tax refunds of $86 million related to alternative minimum tax credits in 2020.

The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, both of which are recorded at estimated or invoiced amounts and do not bear interest. The majority of these receivables have payment terms of 30 days or less. At the end of each reporting period, we assess the collectability of our receivables and estimate the expected credit losses using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions.

We are exposed to credit losses through the receivables generated from sales of crude oil, NGLs and natural gas to our customers. When dealing with the commodity purchasers, we conduct a credit review to assess each counterparty’s ability to pay. The credit review considers our expected billing exposure, timing for payment and the counterparty’s established credit rating with the rating agencies or our internal assessment of the counterparty’s creditworthiness based on our analysis of their financial statements. Our evaluation also considers contract terms and other factors, such as country and/or political risk. A credit limit is established for each counterparty based on the outcome of this review. We may require a bank letter of credit or a prepayment to mitigate credit risk. We monitor our ongoing credit exposure through active review of counterparty balances against contract terms and due dates. The expected credit losses related to receivables with the commodity purchasers were determined using the weighted average probability of default method. We also collect revenues from our non-operated joint properties where other oil and gas exploration and production companies operate the properties and market our share of production and remit payments to us. The current expected credit losses related to these receivables were determined using the loss rate method applied to aging pools.

We are exposed to credit losses from joint interest billings to other joint interest owners for properties we operate. For this group of receivables, the expected credit losses are determined using the loss rate method applied to aging pools. Our counterparties in this group include numerous large, mid-size and small oil and gas exploration and production companies. Although we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings or require a prepayment of future costs through cash calls, our credit loss exposure with this group is more significant due to inherent ownership or billing adjustments. Also, some of our counterparties may experience liquidity problems and may

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not be able to meet their financial obligations to us. We expect that liquidity problems will increase in the future as a result of the recent demand and pricing decline for hydrocarbons. Our current-period provision reflects the anticipated effects caused by the recent market deterioration.

Changes in the allowance for doubtful accounts balance for the three months ended were as follows:    

	March 31,
(In millions)	2020
Beginning balance	$	11
Cumulative-effect adjustment	12
Current period provision (a)	8
Recoveries of amounts previously written off	(1		)
Ending balance	$	30

(a)	Consists of $6 million of joint interest receivables and $2 million of trade receivables.

Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or net realizable 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. The continued decline in crude oil and natural gas prices could affect the value of our inventories and result in future impairments.

(In millions)	March 31, 2020				December 31, 2019
Crude oil and natural gas	$	12			$	10
Supplies and other items	66				62
Inventories	$	78			$	72

(In millions)	March 31, 2020				December 31, 2019
United States	$	16,352			$	16,427
International	471				493
Corporate	80				80
Net property, plant and equipment	$	16,903			$	17,000

We had no exploratory well costs capitalized greater than one year as of March 31, 2020 and December 31, 2019.

During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. We reviewed our long-lived assets for indicators of impairment by conducting a sensitivity analysis of the most impactful inputs to their undiscounted cash flows, including commodity prices, capital spend and reductions in production volumes to correspond with lower capital spending. Our review concluded that the carrying amounts of our long-lived assets are recoverable, with our most at risk asset having undiscounted cash flows that exceeded its $461 million carrying value by approximately 90%. However, further deterioration or a more sustained decline of commodity prices may result in impairment charges in future periods. 

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The following table summarizes impairment charges of proved properties and goodwill and their corresponding fair values.

	Three Months Ended March 31,
	2020								2019
(In millions)	Fair Value				Impairment				Fair Value				Impairment
Long-lived assets held for use	$	—			$	2			$	37			$	6
Goodwill	$	—			$	95			N/A				$	—

•	2020 – Impairments included $95 million of goodwill impairment in the International reporting unit. See Note 14 for further information.

•

2019 – During the three months ended March 31, 2019, we recorded a proved property impairment charge of $6 million, as a result of the anticipated sale of our non-operated interest in the Atrush block (Kurdistan) in our International segment. The related fair value was measured using the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification.

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations for the three months ended were as follows:

	March 31,
(In millions)	2020				2019
Beginning balance	$	254			$	1,145
Incurred liabilities, including acquisitions	1				12
Settled liabilities, including dispositions	(2		)		(109		)
Accretion expense (included in depreciation, depletion and amortization)	3				13
Revisions of estimates	(9		)		11
Held for sale	—				(862		)
Ending balance	$	247			$	210

March 31, 2020

•	Ending balance includes $11 million classified as short-term at March 31, 2020.

March 31, 2019

•	Settled liabilities primarily relate to the sale of our working interest in the Droshky field (Gulf of Mexico), which closed during the first quarter of 2019.

•	Held for sale includes the asset retirement obligations associated with the sale of our U.K. business, which was partially offset by settled liabilities for dispositions primarily related to the Droshky field in the first quarter of 2019. See Note 4 for discussion of the divestitures in further detail.

•	Ending balance includes $18 million classified as short-term at March 31, 2019.

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We enter into various lease agreements to support our operations including drilling rigs, well fracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.

Supplemental balance sheet information related to leases was as follows:

(In millions)		March 31, 2020
Operating Leases:	Balance Sheet Location:
ROU asset	Other noncurrent assets	$	162
Current portion of long-term lease liability	Other current liabilities	$	83
Long-term lease liability	Deferred credits and other liabilities	$	86

Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee – see Note 24. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions)	Operating Lease Future Cash Receipts
2020	$	5
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	89

As of December 31, 2019, our consolidated balance sheet included goodwill of $95 million in the International reporting unit. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. This demand loss resulted in a significant decline in hydrocarbon prices. The commensurate decline in our market capitalization during the first quarter indicated that it was more likely than not that the fair value of the International reporting unit was less than its carrying value.

We estimated the fair value of our International 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 peers from 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, operating expenses and tax rates. The

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assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. Based on the results, we concluded our goodwill was fully impaired, and recorded an impairment of $95 million in the consolidated statements of income for the quarter ended March 31, 2020.

		March 31,
(In millions)		2020				2019
Beginning balance, gross		$	95			$	95
Less: accumulated impairments		—				—
Beginning balance, net		95				95
Impairment		(95		)		—
Ending balance, net		$	—			$	95

For further information regarding the fair value measurement of derivative instruments, see Note 16. All of our commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net 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.

	March 31, 2020
(In millions)	Asset				Liability				Net Asset (Liability)				Balance Sheet Location
Not Designated as Hedges
Commodity	$	176			$	1			$	175			Derivative assets
Total Not Designated as Hedges	$	176			$	1			$	175
Cash Flow Hedges
Interest Rate	$	—			$	20			$	(20	)		Other noncurrent liabilities
Total Designated Hedges	$	—			$	20			$	(20	)
Total	$	176			$	21			$	155

	December 31, 2019
(In millions)	Asset				Liability				Net Asset (Liability)				Balance Sheet Location
Not Designated as Hedges
Commodity	$	9			$	1			$	8			Derivative assets
Commodity	1				—				1				Other noncurrent assets
Commodity	—				5				(5		)		Other current liabilities
Total Not Designated as Hedges	$	10			$	6			$	4
Cash Flow Hedges
Interest Rate	$	2			$	—			$	2			Other noncurrent assets
Total Designated Hedges	$	2			$	—			$	2
Total	$	12			$	6			$	6

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Derivatives Not Designated as Hedges

We have entered into multiple crude oil derivatives indexed to the respective indices as noted in the table below, related to a portion of our forecasted United States sales through 2021. These derivatives consist of three-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. 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 price plus the difference between the floor and the sold put price. These crude oil derivatives were not designated as hedges.

The following table sets forth outstanding derivative contracts as of March 31, 2020, and the weighted average prices for those contracts:

		2020													2021
		Second Quarter				Third Quarter				Fourth Quarter					Full Year
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)		80,000				80,000				80,000					—
Weighted average price per Bbl:
Ceiling		$	66.12			$	64.40			$	64.40				$	—
Floor		$	55.00			$	55.00			$	55.00				$	—
Sold put		$	47.75			$	48.00			$	48.00				$	—
Basis Swaps - Argus WTI Midland (a)
Volume (Bbls/day)		15,000				15,000				15,000					—
Weighted average price per Bbl		$	(0.94	)		$	(0.94	)		$	(0.94	)			$	—
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)		5,000				5,000				5,000					808
Weighted average price per Bbl		$	(7.24	)		$	(7.24	)		$	(7.24	)			$	(7.24	)
Basis Swaps - Argus WTI Houston (c)
Volume (Bbls/day)		26,813				—				—					—
Weighted average price per Bbl		$	(0.75	)		$	—			$	—				$	—
NYMEX Roll Basis Swaps
Volume (Bbls/day)		43,571				—				—					—
Weighted average price per Bbl		$	(1.62	)		$	—			$	—				$	—
Fixed Price Swaps
Volume (Bbls/day)		20,000				—				—					—
Weighted average price per Bbl		$	24.61			$	—			$	—				$	—

(a)	The basis differential price is indexed against Argus WTI Midland.

(b)	The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.

(c)	The basis differential price is indexed against Argus WTI Houston.

Subsequent to March 31, 2020, we terminated our 80,000 bbls/day NYMEX WTI three-way collars and replaced them with 40,000 bbls/day of two-way collars with an average ceiling price of $40.31 and an average floor price of $32.89 and 40,000 bbls/day of fixed price swaps with an average price of $33.79. This termination and subsequent replacement applies only to derivative positions for the second quarter of 2020. Thus, the NYMEX WTI three-way collars for the third and fourth quarters of 2020 remain as presented in the schedule above.

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The following table sets forth outstanding derivative contracts as of May 4, 2020, and the weighted average prices for those contracts:

		2020													2021
		Second Quarter				Third Quarter				Fourth Quarter					Full Year
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)		—				80,000				80,000					—
Weighted average price per Bbl:
Ceiling		$	—			$	64.40			$	64.40				$	—
Floor		$	—			$	55.00			$	55.00				$	—
Sold put		$	—			$	48.00			$	48.00				$	—
NYMEX WTI Two-Way Collars
Volume (Bbls/day)		40,000				—				—					—
Weighted average price per Bbl:
Ceiling		$	40.31			$	—			$	—				$	—
Floor		$	32.89			$	—			$	—				$	—
Fixed Price WTI Swaps
Volume (Bbls/day)		76,703				10,000				—					—
Weighted average price per Bbl:		$	28.99			$	32.77			$	—				$	—
Basis Swaps - Argus WTI Midland (a)
Volume (Bbls/day)		15,000				15,000				15,000					—
Weighted average price per Bbl		$	(0.94	)		$	(0.94	)		$	(0.94	)			$	—
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)		5,000				5,000				5,000					808
Weighted average price per Bbl		$	(7.24	)		$	(7.24	)		$	(7.24	)			$	(7.24	)
Basis Swaps - NYMEX WTI / MEH (c)
Volume (Bbls/day)		26,813				—				—					—
Weighted average price per Bbl		$	(0.75	)		$	—			$	—				$	—
NYMEX Roll Basis Swaps
Volume (Bbls/day)		43,571				60,000				10,000					—
Weighted average price per Bbl		$	(1.62	)		$	(1.58	)		$	(1.94	)			$	—

(a)	The basis differential price is indexed against Argus WTI Midland.

(b)	The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.

(c)	The basis differential price is indexed against Argus WTI Houston.

The mark-to-market impact and settlement of our commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.

	Three Months Ended March 31,
(In millions)	2020				2019
Mark-to-market gain (loss)	$	171			$	(113	)
Net settlements of commodity derivative instruments	$	31			$	22

Derivatives Designated as Cash Flow Hedges

In March 2020, we entered into forward starting interest rate swaps with a notional amount of $350 million to hedge variations in cash flows arising from fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of a future debt issuance in 2022; and an additional $100 million of notional for our future debt issuance in 2025. We expect to refinance both of the debt maturities in 2022 and 2025. The swaps will terminate on

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or prior to the refinancing of the debt and the final value will be reclassified from accumulated other comprehensive income into earnings with each future interest payment. Subsequent to March 31, 2020, we entered into additional forward starting interest rate swaps with a notional amount of $150 million to hedge variations in cash flows related to the same LIBOR interest rate for our debt due in 2022 and $150 million notional for our debt due in 2025.

During 2019, we entered into forward starting interest rate swaps with a total notional amount of $320 million to hedge variations in cash flows related to the 1-month LIBOR component of future lease payments of our future Houston office. These swaps will settle monthly on the same day the lease payment is made with the first swap settlement occurring in January 2022. We expect the first lease payment to commence sometime in the period from December 2021 to May 2022. The last swap will mature on September 9, 2026. See Note 13 for further details regarding the lease of the new Houston office.

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.

	March 31, 2020							December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)				Weighted Average, LIBOR			Aggregate Notional Amount (in millions)				Weighted Average, LIBOR
November 1, 2022	$	350			1.04	%		$	—			—	%
June 1, 2025	$	100			0.96	%		$	—			—	%
September 9, 2026	$	320			1.51	%		$	320			1.51	%

At March 31, 2020, accumulated other comprehensive income included deferred losses of $20 million related to forward starting interest rate swaps. No amounts related to these swaps are expected to impact the consolidated statements of income in the next 12 months.

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2020 and December 31, 2019 by hierarchy level.

	March 31, 2020
(In millions)	Level 1				Level 2				Level 3				Total
Derivative instruments, assets
Commodity(a)	$	29			$	146			$	—			$	175
Derivative instruments, assets	$	29			$	146			$	—			$	175
Derivative instruments, liabilities
Interest rate	$	—			$	(20	)		$	—			$	(20	)
Derivative instruments, liabilities	$	—			$	(20	)		$	—			$	(20	)
Total	$	29			$	126			$	—			$	155

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	December 31, 2019
(In millions)	Level 1				Level 2				Level 3				Total
Derivative instruments, assets
Commodity(a)	$	—			$	7			$	—			$	7
Interest rate	—				2				—				2
Derivative instruments, assets	$	—			$	9			$	—			$	9
Derivative instruments, liabilities
Commodity(a)	$	(3	)		$	—			$	—			$	(3	)
Derivative instruments, liabilities	$	(3	)		$	—			$	—			$	(3	)
Total	$	(3	)		$	9			$	—			$	6

(a)	Derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 15.

Commodity derivatives include three-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps, inputs to the models include only commodity prices and interest rates and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars, inputs to the models include commodity prices, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 15 for detail on the forward starting interest rate swaps.

Fair Value Estimates – Goodwill

See Note 14 for detail information relating to goodwill.

Fair Values – Nonrecurring

See Note 11 for detail on our fair values related to impairments.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, the current portion of our 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 values by individual balance sheet line item at March 31, 2020 and December 31, 2019.

	March 31, 2020								December 31, 2019
(In millions)	Fair Value				Carrying Amount				Fair Value				Carrying Amount
Financial assets
Current assets	$	3			$	4			$	4			$	4
Other noncurrent assets	22				40				26				38
Total financial assets	$	25			$	44			$	30			$	42
Financial liabilities
Other current liabilities	$	42			$	95			$	62			$	90
Long-term debt, including current portion(a)	3,992				5,529				6,174				5,529
Deferred credits and other liabilities	90				81				99				86
Total financial liabilities	$	4,124			$	5,705			$	6,335			$	5,705

(a)	Excludes debt issuance costs.

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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.

Revolving Credit Facility

As of March 31, 2020, we had no borrowings against our $3.0 billion Credit Facility, as described below.

The Credit Facility includes a covenant requiring our total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. In the event of a default, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of March 31, 2020, we were in compliance with this covenant with a ratio of 32%.

Long-term debt

At March 31, 2020, we had $5.5 billion of total debt outstanding, with our next significant debt maturity in the amount of $1.0 billion due November 2022.

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first three months of 2020: 

	Stock Options							Restricted Stock Awards & Units
	Number of Shares			Weighted Average Exercise Price				Awards			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	5,659,731			$	23.55			7,174,386			$	15.88
Granted	1,132,808		(a)	$	10.47			5,337,796			$	8.55
Exercised/Vested	(52,333	)		$	7.22			(2,815,109	)		$	15.93
Canceled	(202,934	)		$	26.25			(200,750	)		$	14.71
Outstanding at March 31, 2020	6,537,272			$	21.33			9,496,323			$	11.77

^(a)    The weighted average grant date fair value of stock option awards granted was $3.82 per share.

Stock-based performance unit awards

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The following summarizes the components of net periodic benefit cost:

	Three Months Ended March 31,
	Pension Benefits								Other Benefits
(In millions)	2020				2019(c)				2020				2019
Service cost	$	5			$	4			$	—			$	—
Interest cost	3				7				1				1
Expected return on plan assets	(3		)		(8		)		—				—
Amortization:
– prior service cost (credit)	(2		)		(2		)		(4		)		(4		)
– actuarial loss	3				2				—				—
Net settlement loss(a)	2				—				—				—
Net periodic benefit cost(b)	$	8			$	3			$	(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)	Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

(c)	Includes amounts related to the noncontributory defined benefit pension plan covering U.K. employees, prior to the plan being transferred to the buyer upon sale of the U.K. asset on July 1, 2019.

During the first three months of 2020, we made contributions of $6 million to our funded pension plan and expect to contribute an additional $22 million this year. During the first three months of 2020, we made payments of $5 million and $4 million related to unfunded pension plans and other postretirement benefit plans.

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

	Three Months Ended March 31,
(In millions)	2020				2019				Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	6			$	6			Other net periodic benefit costs
Amortization of actuarial loss	(3		)		(2		)		Other net periodic benefit costs
Net settlement loss	(2		)		—				Other net periodic benefit costs
Total reclassifications to expense, net of tax (a)	$	1			$	4			Net income

(a)	During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets and as such, there is no tax impact to our postretirement and postemployment plans.

(a)	The three months ended March 31, 2020 and 2019 includes $3 million and $5 million, related to tax refunds.

(b)	In the first quarter of 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), including our $98 million asset retirement obligation.

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Other noncash investing activities include accrued capital expenditures for the three months ended March 31, 2020 and 2019 of $238 million and $250 million.

Equity method investments are assessed for impairment whenever charges in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred that is other than temporary, the carrying value of the equity method investment is written down to fair value. The continued decline in commodity prices resulting from demand contraction related to the global pandemic could affect the investment value of our equity method investees and result in an other than temporary impairment.

During the periods ended March 31, 2020 and December 31, 2019 our equity method investees were considered related parties and included:

•	EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.

•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.

•	AMPCO, in which we have a 45% noncontrolling interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:

(In millions)	Ownership as of March 31, 2020		March 31, 2020				December 31, 2019
EGHoldings	60%		$	294			$	310
Alba Plant LLC	52%		162				163
AMPCO	45%		172				190
Total			$	628			$	663

Summarized financial information for equity method investees is as follows:

	Three Months Ended March 31,
(In millions)	2020				2019
Income data:
Revenues and other income	$	172			$	220
Income from operations	(30		)		49
Net income	(26		)		32

In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. MEGPL is a signatory to the agreements related to our equity method investee, Alba Plant LLC. These agreements contain clauses that cause MEGPL to indemnify the owners of the Alen Unit against actions or inaction by Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental assessments, injury to Alba Plant LLC’s personnel, and damage to or loss of Alba Plant LLC’s automobiles. At this time, we cannot reasonably estimate this obligation as we do not have any history of prior indemnification claims, as completion of the plant modifications is not expected to finish until 2021, and as such, we do not have any history of environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these guarantees since the amount of potential future payments under these indemnification clauses is not determinable.

The agreements to process the third-party Alen Unit gas required the execution of third-party guarantees by Marathon Oil Corporation in favor of the Alen Unit’s owners.  We executed two separate guarantee documents during the second quarter of 2020; one for a maximum of $91 million pertaining to the performance of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining the performance of Alba Plant LLC.  Payment by us would be required if either entity fails to honor its obligations pursuant to the processing agreements. Certain of the Alen Unit owners are also shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We are

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still assessing the effects of these arrangements on our consolidated statements of income and financial position and will record such effects, if any, during the second quarter of 2020.

Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River.  As a result, as of March 31, 2020, we have a $99 million current liability in suspended royalty and working interest revenue, including interest, and have a long-term receivable of $24 million for capital and expenses.

In December 2019, we received a Notice of Violation from the North Dakota Department of Environmental Quality and a verbal notice of enforcement in January 2020 from the North Dakota Industrial Commission, related to a release of produced water in North Dakota. In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. Each enforcement action will likely result in monetary sanctions in excess of $100,000; however, we do not believe these enforcement actions would have a material adverse effect on our consolidated financial position, results of operations or cash flow. 

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. 

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 offset by the prices we receive for 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. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

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•	In response to the current macro environment, we revised our 2020 Capital Budget downward to $1.3 billion from the original plan of $2.4 billion.

•	At the end of the first quarter 2020, we had approximately $3.8 billion of liquidity, comprised of an undrawn $3.0 billion revolving credit facility and $0.8 billion in cash, and no significant near-term debt maturities. We remain investment grade at all three primary rating agencies, with recent reviews by both Fitch and S&P.

•	The quarter-end cash balance decreased by approximately $40 million from year-end, including 9 million of common share repurchases at a cost of $85 million and $40 million of dividends.

•	Restructured commodity derivatives to minimize the near-term crude downside and to protect basis differentials.

•	In April 2020, we took broad-based cost saving measures, including temporary base salary reductions for CEO and other corporate officers through year-end, a reduction in Board of Director compensation through year end, and U.S. employee and contractor workforce reductions.

•	Temporarily suspended the quarterly dividend and share repurchases to maximize liquidity.

•	U.S. net sales volumes increased by 14% during the quarter to 338 mboed, along with U.S. crude oil net sales volumes which increased 16% compared to the same quarter last year.

•	Our net loss per share was $0.06 in the first quarter of 2020 as compared to net income per share of $0.21 in the same period last year. Included in our financial results for the current quarter:

◦	A decrease in revenues from contracts with customers of approximately 15% to $1.0 billion, compared to the same quarter last year, largely due to lower price realizations, partially offset by increased production volumes. Average crude oil price realizations decreased by 19% during the first three months of 2020 as compared to the prior period.

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◦	Recorded non-cash goodwill impairment of $95 million in the International reporting unit during the quarter.

◦	Net gain on commodity derivatives of $202 million for the first quarter of 2020, a nearly $300 million increase from the same period in 2019, which was a net loss of $91 million.

•	Net cash provided by operating activities in the first three months of 2020 increased to $701 million or 36% primarily due changes to working capital, partially offset by a net loss in the first quarter of 2020 as a result of lower commodity price realizations.

(a)	In the first quarter of 2019, we announced the sale of our U.K. business, which closed in the third quarter of 2019. The three months ended March 31, 2019 includes net sales volumes related to the U.K. of 11 mboed. See Note 4 to the consolidated financial statements for further information.

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•	Eagle Ford – Our net sales volumes were 114 mboed in the first quarter of 2020, including oil sales of 72 mbbld and brought 38 gross company-operated wells to sales. In light of current market conditions, we suspended second quarter frac activity and plan to transition to a lower and more continuous level of drilling and completion activity over the second half of the year.

•	Bakken – Our net sales volumes of 110 mboed, including 88 mbbld of oil sales and brought 25 gross company-operated wells to sales. We suspended second quarter frac activity and plan to transition to a lower and more continuous level of drilling and completion activity over the second half of the year.

•	Oklahoma – Our net sales volumes were 73 mboed, including 20 mbbld of oil sales and brought 13 gross company-operated wells to sales. We suspended all drilling and completion operations in light of current market conditions. We do not expect to bring any additional wells to sales in Oklahoma this year.

•	Northern Delaware – Our net sales volumes were 29 mboed, including 17 mbbld of oil sales and brought 6 gross company-operated wells to sales. We suspended all drilling and completion operations and expect only a limited number of wells to sales through the remainder of the year.

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(a)	Includes natural gas acquired for injection and subsequent resale.

•	Equatorial Guinea – Net sales volumes in the first quarter of 2020 were higher compared to the same period in 2019 as a result of a planned triennial turnaround in E.G. completed in the first quarter of 2019 partially offset by natural field decline.

•	United Kingdom – During 2019, we closed on the sale of our U.K. business. See Note 4 to the consolidated financial statements for further information.

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

(b)	Inclusion of realized gains (losses) on crude oil derivative instruments would have impacted average price realizations by $1.47 per bbl and $1.10 per bbl for the first quarter 2020 and 2019.

(c)	Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.

(d)	Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.

(a)	Average of monthly prices obtained from the United States Energy Information Agency website.

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•	conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;

•	changes in expected reserve or production levels;

•	changes in political and economic conditions in the U.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation rates;

•	actions taken by the members of OPEC and Russia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments;

•	risks related to our hedging activities;

•	voluntary and involuntary volume curtailments;

•	delays or cancellations of certain drilling activities;

•	liability resulting from litigation;

•	capital available for exploration and development;

•	the inability of any party to satisfy closing conditions or delays in execution with respect to our asset acquisitions and dispositions;

•	drilling and operating risks;

•	lack of, or disruption in, access to storage capacity, pipelines or other transportation methods;

•	well production timing;

•	availability of drilling rigs, materials and labor, including the costs associated therewith;

•	difficulty in obtaining necessary approvals and permits;

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

•	hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto;

•	shortages of key personnel, including employees, contractors and subcontractors;

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•	cyber-attacks;

•	changes in safety, health, environmental, tax and other regulations or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;

•	other geological, operating and economic considerations; and

•	the risk factors, forward-looking statements and challenges and uncertainties described in our 2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.

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(a)	728,121 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

(b)	In January 2006, we announced a $2.0 billion share repurchase program. Our Board of Directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, by $1.2 billion in December 2013, and by $950 million in July 2019.

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