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 SeptemberJune 30, 20172020
OR
[   ]☐
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 1-51531-1513
mro-20200630_g1.jpg
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware25-0996816
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, TX  Texas  
77056-2723
(Address of principal executive offices)

(713) 629-6600
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of each exchange on which registered
Common Stock, par value $1.00MRONew York Stock Exchange
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 þ No o

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 þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþAccelerated filer
o
Non-accelerated filer
Accelerated filero
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting companyo
☐Emerging growth companyo☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 849,663,522789,439,221 shares of Marathon Oil Corporation common stock outstanding as of OctoberJuly 31, 2017.

2020.



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 20162019 Annual Report on Form 10-K.

Table of Contents
Page
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
Consolidated Statements of Stockholders' Equity (Unaudited)
6
Notes to Consolidated Financial Statements (Unaudited)
67
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
3028
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
4745
Item 4.
Controls and Procedures
4845
Item 1.
Legal Proceedings
4946
Item 1A.
Risk Factors
4946
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
4947
Item 6.
Exhibits
4947
Signatures
5048
 




1

Part I - Financial Information– FINANCIAL INFORMATION
Item 1. Financial Statements


MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
(In millions, except per share data)2020201920202019
Revenues and other income:    
Revenues from contracts with customers$490  $1,381  $1,514  $2,581  
Net gain (loss) on commodity derivatives(70) 16  132  (75) 
Income (loss) from equity method investments(152) 31  (164) 42  
Net gain (loss) on disposal of assets(2) (8) 7  34  
Other income6  13  13  48  
Total revenues and other income272  1,433  1,502  2,630  
Costs and expenses:   
Production129  193  289  380  
Shipping, handling and other operating105  170  249  324  
Exploration26  26  54  85  
Depreciation, depletion and amortization597  605  1,241  1,159  
Impairments—  18  97  24  
Taxes other than income30  79  96  151  
General and administrative88  87  164  181  
Total costs and expenses975  1,178  2,190  2,304  
Income (loss) from operations(703) 255  (688) 326  
Net interest and other(69) (64) (133) (113) 
Other net periodic benefit credit7  2  7  7  
Income (loss) before income taxes(765) 193  (814) 220  
Provision (benefit) for income taxes(15) 32  (18) (115) 
Net income (loss)$(750) $161  $(796) $335  
Net income (loss) per share:    
Basic$(0.95) $0.20  $(1.00) $0.41  
Diluted$(0.95) $0.20  $(1.00) $0.41  
Weighted average common shares outstanding:    
Basic790  813  793  817  
Diluted790  814  793  817  
 Three Months Ended Nine Months Ended
 September 30, September 30,
(In millions, except per share data)2017 2016 2017 2016
Revenues and other income:       
Sales and other operating revenues, including related party$1,114
 $781
 $3,026
 $2,032
Marketing revenues48
 80
 117
 202
Income from equity method investments63
 59
 183
 110
Net gain on disposal of assets19
 47
 26
 281
Other income8
 23
 31
 38
Total revenues and other income1,252
 990
 3,383
 2,663
Costs and expenses: 
  
    
Production194
 160
 521
 532
Marketing, including purchases from related parties49
 80
 121
 201
Other operating109
 183
 309
 373
Exploration294
 83
 352
 289
Depreciation, depletion and amortization641
 522
 1,789
 1,583
Impairments201
 47
 205
 48
Taxes other than income44
 35
 128
 113
General and administrative97
 104
 299
 386
Total costs and expenses1,629
 1,214
 3,724
 3,525
Income (loss) from operations(377) (224) (341) (862)
Net interest and other(35) (89) (199) (256)
Loss on early extinguishment of debt(46) —
 (46) —
Income (loss) from continuing operations before income taxes(458) (313) (586) (1,118)
Provision (benefit) for income taxes141
 (107) 216
 (414)
Income (loss) from continuing operations(599) (206) (802) (704)
Income (loss) from discontinued operations—
 14
 (4,893) (65)
Net income (loss)$(599) $(192) $(5,695) $(769)
Per basic share: 
  
  
  
Income (loss) from continuing operations$(0.70) $(0.24) $(0.94) $(0.87)
Income (loss) from discontinued operations$—
 $0.01
 $(5.76) $(0.08)
Net income (loss)$(0.70) $(0.23) $(6.70) $(0.95)
Per diluted share:       
Income (loss) from continuing operations$(0.70) $(0.24) $(0.94) $(0.87)
Income (loss) from discontinued operations$—
 $0.01
 $(5.76) $(0.08)
Net income (loss)$(0.70) $(0.23) $(6.70) $(0.95)
Dividends per share$0.05
 $0.05
 $0.15
 $0.15
Weighted average common shares outstanding: 
  
  
  
Basic850
 847
 850
 809
Diluted850
 847
 850
 809
The accompanying notes are an integral part of these consolidated financial statements.


2

MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months EndedSix Months Ended
June 30,June 30,
(In millions)2020201920202019
Net income (loss)$(750) $161  $(796) $335  
Other comprehensive income (loss), net of tax   
Change in actuarial loss and other for postretirement and postemployment plans(42) (9) (42) (13) 
Change in derivative hedges unrecognized loss(4) —  (26) —  
Other comprehensive loss(46) (9) (68) (13) 
Comprehensive income (loss)$(796) $152  $(864) $322  
 Three Months Ended Nine Months Ended
 September 30, September 30,
(In millions)2017 2016 2017 2016
Net income (loss)$(599) $(192) $(5,695) $(769)
Other comprehensive income (loss)   
  
  
Postretirement and postemployment plans 
  
  
  
Change in actuarial loss and other5
 —
 17
 (5)
Income tax provision19
 —
 19
 2
Postretirement and postemployment plans, net of tax24
 —
 36
 (3)
Derivative hedges       
Net unrecognized gain (loss)—
 2
 (13) 2
Reclassification of gains on terminated derivative hedges(46) —
 (47) —
Income tax provision21
 —
 21
 —
Derivative hedges, net of tax(25) 2
 (39) 2
Foreign currency hedges 
  
  
  
Net recognized loss reclassified to discontinued operations—
 —
 34
 —
Income tax provision (benefit)—
 —
 (4) —
Foreign currency hedges, net of tax—
 —
 30
 —
Other, Net of Tax1
 1
 2
 (1)
Other comprehensive income (loss)—
 3
 29
 (2)
Comprehensive income (loss)$(599)
$(189)
$(5,666)
$(771)
The accompanying notes are an integral part of these consolidated financial statements.




3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
June 30,December 31,
(In millions, except par value and share amounts)20202019
Assets  
Current assets:  
Cash and cash equivalents$522  $858  
Receivables, less reserve of $23 and $11620  1,122  
Inventories77  72  
Derivative assets79  9  
Other current assets107  74  
Total current assets1,405  2,135  
Equity method investments476  663  
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,216 and $18,00316,424  17,000  
Goodwill—  95  
Other noncurrent assets262  352  
Total assets$18,567  $20,245  
Liabilities  
Current liabilities:  
Accounts payable$696  $1,307  
Payroll and benefits payable76  112  
Accrued taxes77  118  
Other current liabilities216  208  
Total current liabilities1,065  1,745  
Long-term debt5,503  5,501  
Deferred tax liabilities171  186  
Defined benefit postretirement plan obligations194  183  
Asset retirement obligations242  243  
Deferred credits and other liabilities217  234  
Total liabilities7,392  8,092  
Commitments and contingencies
Stockholders’ Equity  
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)$—  $—  
Common stock:  
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2020 and December 31, 2019)937  937  
Held in treasury, at cost – 147 million shares and 141 million shares(4,087) (4,089) 
Additional paid-in capital7,143  7,207  
Retained earnings7,145  7,993  
Accumulated other comprehensive income37  105  
Total stockholders’ equity11,175  12,153  
Total liabilities and stockholders’ equity$18,567  $20,245  
 September 30, December 31,
(In millions, except per share data)2017 2016
Assets   
Current assets:   
Cash and cash equivalents$1,795
 $2,488
Receivables, less reserve of $7 and $6945
 748
Notes receivable745
 —
Inventories132
 136
Other current assets62
 66
Current assets held for sale11
 227
Total current assets3,690
 3,665
Equity method investments836
 931
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,669 and $20,255
17,645
 16,727
Goodwill115
 115
Other noncurrent assets607
 558
Noncurrent assets held for sale54
 9,098
Total assets$22,947
 $31,094
Liabilities 
  
Current liabilities: 
  
Accounts payable$1,313
 $967
Payroll and benefits payable99
 129
Accrued taxes162
 94
Other current liabilities188
 243
Long-term debt due within one year—
 686
Current liabilities held for sale—
 121
Total current liabilities1,762
 2,240
Long-term debt6,488
 6,581
Deferred tax liabilities844
 769
Defined benefit postretirement plan obligations330
 345
Asset retirement obligations1,522
 1,602
Deferred credits and other liabilities217
 225
Noncurrent liabilities held for sale9
 1,791
Total liabilities11,172
 13,553
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 937 million shares (par value $1 per share,
1.1 billion shares authorized)
937
 937
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)
—
 —
Held in treasury, at cost – 87 million and 90 million shares(3,324) (3,431)
Additional paid-in capital7,367
 7,446
Retained earnings6,849
 12,672
Accumulated other comprehensive loss(54) (83)
Total stockholders' equity11,775
 17,541
Total liabilities and stockholders' equity$22,947
 $31,094
The accompanying notes are an integral part of these consolidated financial statements.


4

MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
Nine Months EndedSix Months Ended
September 30,June 30,
(In millions)2017 2016(In millions)20202019
Increase (decrease) in cash and cash equivalentsIncrease (decrease) in cash and cash equivalents  
Operating activities: 
  
Operating activities:  
Net income (loss)$(5,695) $(769)Net income (loss)$(796) $335  
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:  
Discontinued operations4,893
 65
Depreciation, depletion and amortization1,789
 1,583
Depreciation, depletion and amortization1,241  1,159  
Impairments205
 48
Impairments97  24  
Exploratory dry well costs and unproved property impairments294
 196
Exploratory dry well costs and unproved property impairments40  69  
Net (gain) loss on disposal of assets(26) (281)
Net gain on disposal of assetsNet gain on disposal of assets(7) (34) 
Deferred income taxes44
 (476)Deferred income taxes(14) (33) 
Net (gain) loss on derivative instruments(162) 48
Net (gain) loss on derivative instruments(132) 75  
Net cash received in settlement of derivative instruments88
 51
Stock based compensation38
 37
Net settlements of derivative instrumentsNet settlements of derivative instruments57  27  
Pension and other post retirement benefits, netPension and other post retirement benefits, net(31) (41) 
Stock-based compensationStock-based compensation28  32  
Equity method investments, net46
 26
Equity method investments, net180  12  
Changes in:   
Changes in: 
Current receivables(192) 125
Current receivables489  (95) 
Inventories4
 69
Inventories(5) 3  
Current accounts payable and accrued liabilities189
 (212)Current accounts payable and accrued liabilities(456) (158) 
Other current assets and liabilitiesOther current assets and liabilities46  119  
All other operating, net(28) 16
All other operating, net(27) (182) 
Net cash provided by operating activities from continuing operations1,487
 526
Net cash provided by operating activitiesNet cash provided by operating activities710  1,312  
Investing activities: 
  
Investing activities:  
Additions to property, plant and equipment(1,305) (949)Additions to property, plant and equipment(946) (1,262) 
Additions to other assetsAdditions to other assets12  42  
Acquisitions, net of cash acquired(1,828) (902)Acquisitions, net of cash acquired3  —  
Disposal of assets, net of cash transferred to buyer1,757
 837
Disposal of assets, net of cash transferred to the buyerDisposal of assets, net of cash transferred to the buyer9  69  
Equity method investments - return of capital49
 47
Equity method investments - return of capital7  49  
All other investing, net(26) 2
All other investing, net—  (27) 
Net cash used in investing activities from continuing operations(1,353) (965)
Net cash used in investing activitiesNet cash used in investing activities(915) (1,129) 
Financing activities: 
  
Financing activities:  
Borrowings988
 —
Debt repayments(1,764) (1)
Debt extinguishment costs(46) —
Common stock issuance—
 1,236
Purchases of common stock(10) (5)Purchases of common stock(92) (266) 
Dividends paid(128) (119)Dividends paid(40) (82) 
Net cash provided by (used in) financing activities(960) 1,111
Cash Flow from Discontinued Operations:   
Operating activities141
 97
Investing activities(13) (34)
Changes in cash included in current assets held for sale2
 (63)
Net increase in cash and cash equivalents of discontinued operations130
 —
All other financing, netAll other financing, net1  (2) 
Net cash used in financing activitiesNet cash used in financing activities(131) (350) 
Effect of exchange rate on cash and cash equivalents3
 (3)Effect of exchange rate on cash and cash equivalents—  1  
Net increase (decrease) in cash and cash equivalents(693) 669
Net decrease in cash and cash equivalentsNet decrease in cash and cash equivalents(336) (166) 
Cash and cash equivalents at beginning of period2,488
 1,119
Cash and cash equivalents at beginning of period858  1,462  
Cash and cash equivalents at end of period$1,795
 $1,788
Cash and cash equivalents at end of period$522  $1,296  
Reconciliation of cash and cash equivalentsReconciliation of cash and cash equivalents
Cash and cash equivalentsCash and cash equivalents$522  $961  
Cash and cash equivalents included in current assets held for saleCash and cash equivalents included in current assets held for sale—  335  
Total cash and cash equivalentsTotal cash and cash equivalents$522  $1,296  
The accompanying notes are an integral part of these consolidated financial statements.
5

MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity (Unaudited)
 Total Equity of Marathon Oil Stockholders
(In millions)Preferred
Stock		Common
Stock		Treasury
Stock		Additional
Paid-in
Capital		Retained
Earnings		Accumulated
Other
Comprehensive
Income (Loss)		Total
Equity
Six Months Ended June 30, 2019
December 31, 2018 Balance$—  $937  $(3,816) $7,238  $7,706  $63  12,128  
Cumulative-effect adjustment—  —  —  —  (31) —  (31) 
Shares issued - stock-based compensation—  —  101  (39) —  —  62  
Shares repurchased—  —  (30) —  —  —  (30) 
Stock-based compensation—  —  —  (50) —  —  (50) 
Net income—  —  —  —  174  —  174  
Other comprehensive loss—  —  —  —  —  (4) (4) 
Dividends paid (per share amount of $0.05)—  —  —  —  (41) —  (41) 
March 31, 2019 Balance$—  $937  $(3,745) $7,149  $7,808  $59  $12,208  
Shares issued - stock-based compensation—  —  (3) 5  —  —  2  
Shares repurchased—  —  (236) —  —  —  (236) 
Stock-based compensation—  —  —  16  —  —  16  
Net income—  —  —  —  161  —  161  
Other comprehensive loss—  —  —  —  —  (9) (9) 
Dividends paid (per share amount of $0.05)—  —  —  —  (41) —  (41) 
June 30, 2019 Balance$—  $937  $(3,984) $7,170  $7,928  $50  $12,101  
Six Months Ended June 30, 2020
December 31, 2019 Balance$—  $937  $(4,089) $7,207  $7,993  $105  12,153  
Cumulative-effect adjustment (Note 2)—  —  —  —  (12) —  (12) 
Shares issued - stock based compensation—  —  121  (83) —  —  38  
Shares repurchased—  —  (91) —  —  —  (91) 
Stock-based compensation—  —  —  (22) —  —  (22) 
Net loss—  —  —  —  (46) —  (46) 
Other comprehensive loss—  —  —  —  —  (22) (22) 
Dividends paid (per share amount of $0.05)—  —  —  —  (40) —  (40) 
March 31, 2020 Balance$—  $937  $(4,059) $7,102  $7,895  $83  $11,958  
Shares issued - stock-based compensation—  —  (28) 20  —  —  (8) 
Stock-based compensation—  —  —  21  —  —  21  
Net loss—  —  —  —  (750) —  (750) 
Other comprehensive loss—  —  —  —  —  (46) (46) 
June 30, 2020 Balance$—  $937  $(4,087) $7,143  $7,145  $37  $11,175  
The accompanying notes are an integral part of these consolidated financial statements.




6
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 20162019 Annual Report on Form 10-K. The results of operations for the thirdsecond quarter and first ninesix months of 20172020 are not necessarily indicative of the results to be expected for the full year.
As a result of the announcement to divest of our Canadian business in the first quarter 2017 and its subsequent closing in the second quarter of 2017, we have reflected this business as discontinued operations in all periods presented. Assets and liabilities are presented as held for sale in the historical periods in the consolidated balance sheets. The disclosures in this report related to the results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted. The characteristics and composition of our North America E&P reporting segment remained unchanged and there was no effect on previously reported segment information. As all our remaining properties within the segment are located within the United States, we concluded that our North America E&P segment would be renamed United States E&P segment, effective June 30, 2017. During the first nine months, no changes occurred to our International E&P segment. See Note 6 for discussion of the divestiture in further detail and Note 7 for further information on our reportable segments.
During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employees' behalf will be presented within the financing activities section instead of the operating activities section of the statement of cash flows. We have elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for nine months ended September 30, 2016. Excess tax benefits will be classified as an operating activity within the statement of cash flows on a prospective basis; as such, prior periods were not adjusted. See Note 2 for additional discussion.

2. Accounting Standards
Not YetRecently Adopted
In May 2014 and August 2015, 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 shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial application (“modified retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method. Based on our assessment to date, we do not expect the adoption of this ASU to have a material impact on our consolidated results of operations, financial position or cash flows. However, we do expect to change our presentation of future marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the nine months ended September 30, 2017, we estimate this impact to be approximately $90 million in marketing revenue and expenses in our consolidated results of operations. We continue to evaluate the disclosure requirements, are developing accounting policies, and assessing changes to the relevant business processes and the control activities as a result of this standard.Financial instruments – credit losses
In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. We will adopt this standard in the first quarter of 2018 on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our results of operations, financial position, or cash flows.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We will adopt this standard in the first quarter of 2018 on a retrospective basis. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated statements of cash flows and related disclosures.
In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. We plan to adopt this standard in the first quarter of 2018 on a retrospective basis. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures.
In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. This standard is effective for us in the first quarter of 2018 and will be applied using the modified retrospective approach. Early adoption is permitted. We plan to adopt this new standard in the first quarter of 2018 concurrently with the new revenue recognition standard. 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 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard is effective for us in the first quarter of 2018 and shall be applied on a prospective basis. Early adoption is permitted for certain transactions as described in the guidance. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. We plan to adopt this standard in the first quarter of 2018 and do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 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 does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and shall be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. While we will have to recognize a right of use asset and lease liability on the adoption date, we continue to evaluate the provisions of this accounting standards update and assessing the effects it will have on our consolidated results of operations, financial position or cash flows.
In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this accounting standards update, including transition requirements, and are assessing the impact it may have on our results of operations, financial position, or cash flows.

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.
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 current “incurred loss” model. This standard is effectivemodel used previously. See Note 8 for us in the first quarter of 2020 and will be adoptedmore information on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. 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.credit losses.
Recently 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 was effective for us in the first quarter of 2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our financial statements.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in the first quarter of 2017, and was applied prospectively. 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
During the second quarter of 2017 we closed on the sale of our Canadian business, which included our 20% undivided interest in the Athabasca Oil Sands Project (AOSP). The owners of the AOSP contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg RiverIncome (loss) and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  This contract was transferred to the purchaser of our Canadian business upon closing of the sale in the second quarter of 2017. Historically, this contract qualified as a variable interest contractual arrangement, and the Corridor Pipeline qualified as a VIE.  Prior to the closing of the sale of our Canadian business, we held this variable interest but were not the primary beneficiary because our shipments were only 20% of the total; therefore, the Corridor Pipeline was not consolidated by us. See Note 6 for further discussion regarding dispositions.Dividends per Common Share

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



4.Income (Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options in all years,periods, provided the effect is not antidilutive. The per share calculations below exclude 107 million and 11 millionof stock options for each of the three and six months ended June 30, 2020 and 6 million of stock options for each of the three and six months ended June 30, 2019 that were antidilutive.
Three Months Ended June 30,Six Months Ended June 30,
(In millions, except per share data)2020201920202019
Net income (loss)$(750) $161  $(796) $335  
Weighted average common shares outstanding790  813  793  817  
Effect of dilutive securities—  1  —  —  
Weighted average common shares, diluted790  814  793  817  
Net income (loss) per share:
Basic$(0.95) $0.20  $(1.00) $0.41  
Diluted$(0.95) $0.20  $(1.00) $0.41  
Dividends per share$—  $0.05  $0.05  $0.10  
4. Dispositions
International Segment
In July 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and Marathon Oil West of Shetlands Limited) for proceeds of approximately $95 million which reflects the assumption by RockRose Energy PLC (the buyer) of the U.K. business’ cash equivalent balance and working capital balance as of year-end 2018. Our income before income taxes relating to our U.K. business for the three and nine month periodssix months ended SeptemberJune 30, 20172019, was $18 million and 13 million stock options for the three and nine month periods ended September 30, 2016 that were antidilutive.
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions, except per share data)2017 2016 2017 2016
Income (loss) from operations$(599) $(206) $(802) $(704)
Income (loss) from discontinued operations—
 14
 (4,893) (65)
Net income (loss)$(599) $(192) $(5,695) $(769)
        
Weighted average common shares outstanding850
 847
 850
 809
Per basic share:       
Income (loss) from continuing operations$(0.70) $(0.24) $(0.94) $(0.87)
Income (loss) from discontinued operations$—
 $0.01
 $(5.76) $(0.08)
Net income$(0.70) $(0.23) $(6.70) $(0.95)
Per diluted share:       
Income (loss) from continuing operations$(0.70) $(0.24) $(0.94) $(0.87)
Income (loss) from discontinued operations$—
 $0.01
 $(5.76) $(0.08)
Net income$(0.70) $(0.23) $(6.70) $(0.95)

5. Acquisitions
2017 - United States E&P
In October 2017, we executed a purchase agreement to acquire additional acreage in the Northern Delaware basin of New Mexico from a private seller for $63 million in cash, excluding closing adjustments. We expect the acquisition to close in the fourth quarter of 2017 with cash on hand.$28 million.
In the second quarter of 2017,2019, we closed on the sale of our acquisitions to acquire approximately 91,000 net acres15% non-operated interest in the Permian basin, including over 70,000 net acresAtrush block in the Northern Delaware basinKurdistan for proceeds of New Mexico. On May 1, 2017, we closed on our acquisition with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately 70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017, we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700$63 million, in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation.before closing adjustments.
2016 - United States E&P
7
On August 1, 2016, we closed on our acquisition of PayRock Energy Holdings, LLC (“PayRock”), a portfolio company of EnCap Investments, including approximately 61,000 net surface acres in the oil window of the Anadarko Basin STACK play in Oklahoma. The purchase price of $904 million, subject to closing adjustments, was paid with cash on hand. We accounted for this transaction as an asset acquisition, with a majority of the purchase price allocated to unproved property within property, plant and equipment.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


5. Revenues

6.Dispositions
Oil Sands Mining Segment
On May 31, 2017 we closed onThe 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 Canadian business, which included our 20% non-operated interestcustomers in the AOSP to ShellUnited States and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the termsvarious international locations.
As of the agreement, $1.8 billion was paid to us upon closingJune 30, 2020 and the remaining proceeds will be paidDecember 31, 2019, receivables from contracts with customers, included in the first quarter of 2018. At closing we received two notes receivablereceivables, less reserves were $487 million and $837 million, respectively.
The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas for the remaining proceeds, each with a face value of $375 million. We initially recorded these notes receivable at fair valuethree and in subsequent periods, will report them at amortized cost. See Note 14 for fair value measurements. Our notes receivable are with 10084751 Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant and equipment of our Canadian business. As the effective date of the transaction is January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business that were recorded in our financial statements but transferred to the buyer upon closing.six months ended June 30 as follows:
Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our consolidated statements of income as discontinued operations:United States
Three Months Ended June 30, 2020
(In millions)Eagle FordBakkenOklahomaNorthern DelawareOther U.S.Total
Crude oil and condensate$142  $147  $32  $33  $7  $361  
Natural gas liquids16  3  13  4  1  37  
Natural gas20  5  24  4  1  54  
Other1�� —  —  —  9  10  
Revenues from contracts with customers$179  $155  $69  $41  $18  $462  
Three Months Ended June 30, 2019
(In millions)Eagle FordBakkenOklahomaNorthern DelawareOther U.S.Total
Crude oil and condensate$350  $453  $111  $77  $30  $1,021  
Natural gas liquids30  15  31  7  1  84  
Natural gas32  6  36  1  4  79  
Other1  —  —  —  15  16  
Revenues from contracts with customers$413  $474  $178  $85  $50  $1,200  
Six Months Ended June 30, 2020
(In millions)Eagle FordBakkenOklahomaNorthern DelawareOther U.S.Total
Crude oil and condensate$449  $477  $116  $107  $40  $1,189  
Natural gas liquids31  13  34  7  3  88  
Natural gas44  13  53  7  4  121  
Other3  —  —  —  31  34  
Revenues from contracts with customers$527  $503  $203  $121  $78  $1,432  

Six Months Ended June 30, 2019
(In millions)Eagle FordBakkenOklahomaNorthern DelawareOther U.S.Total
Crude oil and condensate$668  $825  $188  $141  $58  $1,880  
Natural gas liquids65  25  53  15  3  161  
Natural gas66  18  81  7  10  182  
Other3  —  —  —  36  39  
Revenues from contracts with customers$802  $868  $322  $163  $107  $2,262  
8
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Total sales and other revenues and other income $—
 $239
 $431
 $598
Net gain (loss) on disposal of assets —
 —
 (43) —
Total revenues and other income —
 239
 388
 598
Costs and expenses:        
Production expenses —
 135
 254
 441
Depreciation, depletion and amortization —
 72
 40
 181
Impairments —
 —
 6,636
 —
Other —
 9
 25
 69
Total costs and expenses —
 216
 6,955
 691
Pretax income (loss) from discontinued operations —
 23
 (6,567) (93)
Provision (benefit) for income taxes —
 9
 (1,674) (28)
Income (loss) from discontinued operations $—
 $14
 $(4,893) $(65)
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


International
Three Months Ended June 30, 2020
(In millions)E.G.
Crude oil and condensate$20 
Natural gas liquids1 
Natural gas7 
Revenues from contracts with customers$28 
Three Months Ended June 30, 2019
(In millions)E.G.U.K.Other Int’lTotal
Crude oil and condensate$101  $51  $9  $161  
Natural gas liquids1  —  —  1  
Natural gas9  4  —  13  
Other—  6  —  6  
Revenues from contracts with customers$111  $61  $9  $181  
Six Months Ended June 30, 2020
(In millions)E.G.
Crude oil and condensate$65 
Natural gas liquids2 
Natural gas15 
Revenues from contracts with customers$82 
Six Months Ended June 30, 2019
(In millions)E.G.U.K.Other Int’lTotal
Crude oil and condensate$148  $107  $19  $274  
Natural gas liquids2  1  —  3  
Natural gas16  12  —  28  
Other—  14  —  14  
Revenues from contracts with customers$166  $134  $19  $319  
9

The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at September 30, 2017 and December 31, 2016:
  September 30, December 31,
(In millions) 2017 2016
Assets held for sale    
Current assets:    
Cash and cash equivalents $—
 $2
Accounts receivables —
 129
Inventories —
 91
Other —
 4
Total current assets held for sale—discontinued operations —
 226
Total current assets held for sale—continuing operations 11
 1
Total current assets held for sale $11
 $227
     
Noncurrent assets:    
Property, plant and equipment, net $—
 $8,991
Other —
 106
Total noncurrent assets held for sale—discontinued operations —
 9,097
Total noncurrent assets held for sale—continuing operations 54
 1
Total noncurrent assets held for sale $54
 $9,098
     
Liabilities associated with assets held for sale    
Current liabilities:    
Accounts payable $—
 $111
Other —
 10
Total current liabilities held for sale—discontinued operations —
 121
Total current liabilities held for sale—continuing operations —
 —
Total current liabilities held for sale $—
 $121
     
Noncurrent liabilities:    
Asset retirement obligations $—
 $95
Deferred tax liabilities —
 1,669
Other —
 20
Total noncurrent liabilities held for sale—discontinued operations —
 1,784
Total noncurrent liabilities held for sale—continuing operations 9
 7
Total noncurrent liabilities held for sale $9
 $1,791
United States E&P Segment
As disclosed above, we closed on the sale of our Canadian business in May of 2017. This sale included interests in our exploration stage in-situ leases which were included within our historically named North America E&P Segment. See Note 1 for further detail. These interests have been reflected as discontinued operations and are included within the disclosure above.
In July 2017, we entered into an agreement to sell certain conventional assets in Oklahoma. We closed on the sale in September 2017 for proceeds of $25 million, subject to closing adjustments, and recognized a pre-tax gain of $21 million.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas and New Mexico. The sale closed in late October for proceeds of $235 million, and we recognized a total pre-tax gain of $63 million. During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to multiple purchasers for combined proceeds of approximately $67 million, and recognized a total pre-tax gain of $55 million.
In April 2016, we announced the sale of our Wyoming upstream and midstream assets. During the second quarter 2016, we received proceeds of approximately $690 million and recorded a pre-tax gain of $266 million with the remaining asset sales closing in November 2016 for proceeds of $155 million, excluding closing adjustments. A pre-tax gain of $38 million was recognized in the fourth quarter 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 and New Mexico, for a combined total of approximately $80 million in proceeds. We closed on certain of the asset sales and recognized a net pre-tax loss on sale of $48 million in the second quarter of 2016. In October 2017 we closed on the remaining Piceance basin asset sale and expect to recognize a pre-tax gain of approximately $30 million in the fourth quarter of 2017.
International E&P Segment
In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. Certain of these assets are classified as held for sale in the consolidated balance sheet as of September 30, 2017, with total assets of $63 million and total liabilities of $2 million. We expect these transactions to close within one year. See Note 13 for further detail on impairment expenses recognized concurrently with these agreements.

7.6. Segment Information
        We have two2 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. E&P”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States
Int’l E&P•International (“Int’l”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States andas well as produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea (“E.G.”)
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).        Segment income (loss) represents income (loss) which excludes certain items not allocated to our operating segments, net of income taxes, attributable to the operating segments.taxes. A portion of our corporate and operations support 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 impairments of proved property, goodwill, and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension settlement lossessettlements and curtailments, or other items (as determined by the CODM)chief operating decision maker (“CODM”)) are not allocated to operating segments.
As discussed
 Three Months Ended June 30, 2020
(In millions)U.S.Int’lNot Allocated to SegmentsTotal
Revenues from contracts with customers$462  $28  $—  $490  
Net gain (loss) on commodity derivatives26  —  (96) 
(b)
(70) 
Loss from equity method investments—  —  (152) 
(c)
(152) 
Net loss on disposal of assets—  —  (2) (2) 
Other income3  2  1  6  
Less costs and expenses:
Production114  15  —  129  
Shipping, handling and other operating91  1  13  105  
Exploration26  —  —  26  
Depreciation, depletion and amortization569  22  6  597  
Taxes other than income30  —  —  30  
General and administrative32  3  53  
(d)
88  
Net interest and other—  —  69  69  
Other net periodic benefit credit—  —  (7) 
(e)
(7) 
Income tax benefit(6) (5) (4) (15) 
Segment loss$(365) $(6) $(379) $(750) 
Total assets$16,791  $1,144  $632  $18,567  
Capital expenditures(a)
$137  $—  $2  $139  
(a)Includes accruals.
(b)Unrealized loss on commodity derivative instruments (See Note 15).
(c)Partial impairment of investment in Note 6, we closed on the saleequity method investee (See Note 23).
(d)Includes severance expenses associated with workforce reductions of our Canadian business, which includes our Oil Sands Mining segment$13 million.
(e)Includes pension settlement loss of $14 million and exploration stage in-situ leases, in the second quarterpension curtailment gain of 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented. Additionally, we have renamed our North America E&P segment to United States E&P segment effective June 30, 2017 in all periods presented. See Note 1 for further information.$17 million (SeeNote 20).
10
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 Three Months Ended June 30, 2019
(In millions)U.S.Int’lNot Allocated to SegmentsTotal
Revenues from contracts with customers$1,200  $181  $—  $1,381  
Net gain on commodity derivatives5  —  11  
(b)
16  
Income from equity method investments—  31  —  31  
Net loss on disposal of assets—  —  (8) 
(c)
(8) 
Other income4  2  7  13  
Less costs and expenses:
Production147  46  —  193  
Shipping, handling and other operating147  10  13  170  
Exploration26  —  —  26  
Depreciation, depletion and amortization561  38  6  605  
Impairments—  —  18  
(d)
18  
Taxes other than income79  —  —  79  
General and administrative31  8  48  87  
Net interest and other—  —  64  64  
Other net periodic benefit credit—  (1) (1) (2) 
Income tax provision3  17  12  32  
Segment income (loss)$215  $96  $(150) $161  
Total assets$17,539  $2,913  $830  $21,282  
Capital expenditures(a)
$686  $10  $5  $701  
(a)Includes accruals.
(b)Unrealized gain on commodity derivative instruments (See Note 15).
(c)Primarily related to the sale of certain non-core proved properties in our International segment (see Note4).
(d)Primarily as a result of the anticipated sale of non-core proved properties in our United States segment (See Note 11).









11

 Three Months Ended September 30, 2017
  Not Allocated  
(In millions)U.S. E&P Int'l E&P to Segments Total
Sales and other operating revenues$806
 $364
 $(56)
(c) 
$1,114
Marketing revenues12
 36
 —
 48
Total revenues818
 400
 (56) 1,162
Income from equity method investments—
 63
 —
 63
Net gain on disposal of assets and other income4
 —
 23
(d) 
27
Less:       
Production expenses121
 73
 —
 194
Marketing costs14
 35
 —
 49
Exploration expenses41
 3
 250
(e) 
294
Depreciation, depletion and amortization531
 102
 8
 641
Impairments—
 —
 201
(f) 
201
Other expenses (a)
109
 40
 57
(g) 
206
Taxes other than income44
 —
 —
 44
Net interest and other—
 —
 35
(h) 
35
Loss on early extinguishment of debt—
 —
 46
(i) 
46
Income tax provision (benefit)—
 106
 35
 141
Segment income (loss) / Income (loss) from continuing operations$(38) $104
 $(665) $(599)
Capital expenditures (b)
$541
 $4
 $9
 $554
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized loss on commodity derivative instruments.
(d)
Primarily related to the sale of certain conventional assets in Oklahoma. (See Note 6.)
(e)
Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13.)
(f)
Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13.)
(g)
Includes pension settlement loss of $8 million. (See Note 8.)
(h)
Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 15.)
(i)
Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 17.)
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 Six Months Ended June 30, 2020
(In millions)U.S.Int’lNot Allocated to SegmentsTotal
Revenues from contracts with customers$1,432  $82  $—  $1,514  
Net gain on commodity derivatives57  —  75  
(b)
132  
Loss from equity method investments—  (12) (152) 
(c)
(164) 
Net gain on disposal of assets—  —  7  7  
Other income7  4  2  13  
Less costs and expenses:
Production257  32  —  289  
Shipping, handling and other operating231  4  14  249  
Exploration54  —  —  54  
Depreciation, depletion and amortization1,186  43  12  1,241  
Impairments—  —  97  
(d)
97  
Taxes other than income96  —  —  96  
General and administrative64  7  93  
(e)
164  
Net interest and other—  —  133  133  
Other net periodic benefit credit—  —  (7) 
(f)
(7) 
Income tax benefit(7) (5) (6) (18) 
Segment loss$(385) $(7) $(404) $(796) 
Total assets$16,791  $1,144  $632  $18,567  
Capital expenditures(a)
$698  $—  $9  $707  

(a)Includes accruals.
(b)Unrealized gain on commodity derivative instruments (SeeNote 15).
(c)Partial impairment of investment in equity method investee (See Note 23).
(d)Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 14).
(e)Includes severance expenses associated with workforce reductions of $13 million.
(f)Includes pension settlement loss of $16 million and pension curtailment gain of $17 million (SeeNote 20).

12
 Three Months Ended September 30, 2016
  Not Allocated  
(In millions)U.S. E&P Int'l E&P to Segments Total
Sales and other operating revenues$604
 $152
 $25
(c) 
$781
Marketing revenues44
 36
 —
 80
Total revenues648
 188
 25
 861
Income from equity method investments—
 59
 —
 59
Net gain on disposal of assets and other income19
 7
 44
(d) 
70
Less:       
Production expenses113
 47
 —
 160
Marketing costs45
 35
 —
 80
Exploration expenses35
 10
 38
 83
Depreciation, depletion and amortization443
 66
 13
 522
Impairments—
 —
 47
(e) 
47
Other expenses (a)
85
 18
 184
(f) 
287
Taxes other than income35
 —
 —
 35
Net interest and other—
 —
 89
 89
Income tax provision (benefit)(30) 19
 (96) (107)
Segment income (loss) / Income (loss) from continuing operations$(59) $59
 $(206) $(206)
Capital expenditures (b)
$216
 $18
 $3
 $237
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized gain on commodity derivative instruments.
(d)
Primarily related to certain non-operated assets in West Texas and New Mexico. (See Note 6.)
(e)
Proved property impairments. (See Note 13.)
(f)
Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $113 million and pension settlement loss of $14 million. (See Note 8.)

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)




Six Months Ended June 30, 2019
(In millions)U.S.Int’lNot Allocated to SegmentsTotal
Revenue from contracts with customers$2,262  $319  $—  $2,581  
Net gain (loss) on commodity derivatives27  —  (102) 
(b)
(75) 
Income from equity method investments—  42  —  42  
Net gain on disposal of assets—  —  34  
(c)
34  
Other income5  5  38  
(d)
48  
Less costs and expenses:
Production286  96  (2) 380  
Shipping, handling and other operating287  23  14  324  
Exploration85  —  —  85  
Depreciation, depletion and amortization1,075  72  12  1,159  
Impairments—  —  24  
(e)
24  
Taxes other than income153  —  (2) 151  
General and administrative60  15  106  181  
Net interest and other—  —  113  113  
Other net periodic benefit credit—  (3) (4) (7) 
Income tax provision (benefit)1  6  (122) 
(f)
(115) 
Segment income (loss)$347  $157  $(169) $335  
Total assets$17,539  $2,913  $830  $21,282  
Capital expenditures(a)
$1,292  $15  $8  $1,315  
(a)Includes accruals.
(b)Unrealized loss on commodity derivative instruments (SeeNote 15).
(c)Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico).
(d)Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit(SeeNote 7).
(e)Primarily as a result of anticipated sales of certain non-core proved properties in our International and United States segments.
(f)Primarily relates to the settlement of the 2010-2011 Federal Tax Audit (SeeNote 7).


13

 Nine Months Ended September 30, 2017
  Not Allocated  
(In millions)U.S. E&P Int'l E&P to Segments Total
Sales and other operating revenues$2,175
 $787
 $64
(c) 
$3,026
Marketing revenues25
 92
 —
 117
Total revenues2,200
 879
 64
 3,143
Income from equity method investments—
 183
 —
 183
Net gain on disposal of assets and other income11
 14
 32
(d) 
57
Less:       
Production expenses348
 173
 —
 521
Marketing costs30
 91
 —
 121
Exploration expenses97
 5
 250
(e) 
352
Depreciation, depletion and amortization1,498
 266
 25
 1,789
Impairments4
 —
 201
(f) 
205
Other expenses (a)
342
 83
 183
(g) 
608
Taxes other than income116
 —
 12
 128
Net interest and other—
 —
 199
(h) 
199
Loss on early extinguishment of debt—
 —
 46
(i) 
46
Income tax provision (benefit)—
 202
 14
 216
Segment income (loss) / Income (loss) from continuing operations$(224) $256
 $(834) $(802)
Capital expenditures (b)
$1,465
 $27
 $20
 $1,512
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized gain on commodity derivative instruments.
(d)
Primarily related to the sale of certain conventional assets in Oklahoma. (See Note 6.)
(e)
Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13.)
(f)
Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13.)
(g)
Includes pension settlement loss of $25 million. (See Note 8.)
(h)
Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 15.)
(i)
Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 17.)

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



 Nine Months Ended September 30, 2016
  Not Allocated  
(In millions)U.S. E&P Int'l E&P to Segments Total
Sales and other operating revenues$1,714
 $407
 $(89)
(c) 
$2,032
Marketing revenues128
 74
 —
 202
Total revenues1,842
 481
 (89) 2,234
Income from equity method investments—
 110
 —
 110
Net gain on disposal of assets and other income22
 20
 277
(d) 
319
Less:       
Production expenses376
 156
 —
 532
Marketing costs129
 72
 —
 201
Exploration expenses90
 20
 179
(e) 
289
Depreciation, depletion and amortization1,363
 184
 36
 1,583
Impairments1
 —
 47
(f) 
48
Other expenses (a)
300
 56
 403
(g) 
759
Taxes other than income112
 —
 1
 113
Net interest and other—
 —
 256
 256
Income tax provision (benefit)(183) 5
 (236) (414)
Segment income (loss) / Income (loss) from continuing operations$(324) $118
 $(498) $(704)
Capital expenditures (b)
$684
 $62
 $11
 $757
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized loss on commodity derivative instruments.
(d)
Primarily related to net gain on disposal of assets. (See Note 6.)
(e)
Impairments primarily associated with decision to not drill remaining Gulf of Mexico undeveloped leases. (See Note 13.)
(f)
Proved property impairments. (See Note 13.)
(g)
Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $113 million and pension settlement loss of $93 million and severance related expenses associated with workforce reductions of $8 million. (See Note 8.)

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



8.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
 Three Months Ended September 30,
  Pension Benefits Other Benefits
(In millions)2017 2016 2017 2016
Service cost$5
 $6
 $—
 $1
Interest cost7
 9
 2
 3
Expected return on plan assets(10) (12) —
 —
Amortization: 
  
  
  
– prior service cost (credit)(3) (2) (2) (1)
– actuarial loss3
 4
 —
 —
Net settlement loss (a)
8
 14
 —
 —
Net periodic benefit cost$10
 $19
 $—
 $3
 Nine Months Ended September 30,
  Pension Benefits Other Benefits
(In millions)2017 2016 2017 2016
Service cost$16
 $18
 $1
 $3
Interest cost22
 30
 6
 8
Expected return on plan assets(32) (40) —
 —
Amortization:   
  
  
– prior service cost (credit)(7) (7) (5) (3)
– actuarial loss7
 11
 —
 —
Net settlement loss (a)
25
 93
 —
 —
Net periodic benefit cost$31

$105

$2

$8
(a)
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan’s total service and interest cost for that year.

During the first nine months of 2017, we recorded the effects of settlements of our U.S. and U.K. 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 nine months of 2017, we made contributions of $45 million to our funded pension plans and we expect to make additional contributions up to an estimated $8 million over the remainder of 2017.  During the first nine months of 2017, we made payments of $10 million and $16 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



9.7. 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 7. 6.
For the third quarterthree and first ninesix months of 2017ended June 30, 2020 and 2016,2019, our effective income tax rates on continuing operations were as follows:
  Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2017 2016 2017 2016
Total pre-tax income (loss) from continuing operations $(458) $(313) $(586) $(1,118)
Total income tax expense (benefit) $141
 $(107) $216
 $(414)
Effective income tax expense (benefit) rate on continuing operations 31% (34)% 37% (37)%
         
Income taxes at the statutory tax rate of 35% $(160) $(109) $(205) $(390)
Effects of foreign operations 31
 (8) 29
 (39)
Adjustments to valuation allowances 228
 11
 361
 17
State income taxes —
 (2) (13) (4)
Other federal tax effects 42
 1
 44
 2
Income tax expense (benefit) on continuing operations $141
 $(107) $216
 $(414)
Three Months Ended June 30,Six Months Ended June 30,
2020201920202019
Effective income tax rate(a)
2 %17 %2 %(52)%

Income tax expense for the third quarter and first nine months of 2017 was impacted by a full valuation allowance on(a)In all periods presented, we maintained our net federal deferred tax assets generated in 2017 and increased sales volumes in our Libyan operations where the statutory income tax rate is in excess of 90%. Our Libya income tax expense was $102 million in the third quarter and $179 million in the first nine months of 2017 compared to a benefit of $16 million and $39 million for the same periods last year. Additionally, for the third quarter and first nine months of 2017, income tax expense was impacted by a onetime, non-cash deferred tax charge of $41 million related to a reclassification of the valuation allowance on our net federal deferred tax assets between other comprehensive income and income from continuing operations.
In the first nine months of 2017 we settled our 2011-2013 Alaska income tax audit, which resulted in the recognition of a tax benefit totaling $13 million. As of September 30, 2017 there are no uncertain tax positions for which it is reasonably possible that the amount would significantly increase or decrease in the next twelve months.  However, as discussed in Note 21, we may be required to adjust the timing of our tax deduction for decommissioning costs and make a payment to the U.K. tax authorities of approximately $130 million in the next twelve months, which would be recovered as future decommissioning activities are performed and deductions claimed. We estimate that any revisions to current and deferred tax liabilities, if we do not prevail, would have no cumulative adverse earnings impact in our consolidated results of operations.  While we believe that it is more likely than not that we will prevail in the Tribunal, if we do not, we have the option to seek appeal. 
The effective tax rate change between years for the third quarter and first nine months of 2017 and 2016, was driven by the full valuation allowance on our net federal deferred tax assets generated in 2017, and the impacts of foreign operations which includes the tax effects associated with increased sales volumes in Libya.
The impact of foreign operations for the third quarter and first nine months of 2017 totaled tax expense of $31 million for three months ended September 30, 2017 and $29 million for the first nine months of 2017 due to income tax rate differentials from the U.S. statutory rate of 35% associated with foreign operations in Libya, E.G. and the U.K. This was offset by deferred tax benefits being generated in the U.K. related to future tax refunds associated with abandonment costs.
In Libya, reliable estimates of 2017 and 2016 annual ordinary income from our Libyan 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 impacts applicable to Libyan ordinary income (loss) were recorded as a discrete item in the third quarter and the first nine months of 2017 and 2016.  For the third quarter and the first nine months of 2017 and 2016, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective income tax expense and benefit rates would be an expense of 7% and benefit of 31% for the third quarter of 2017 and 2016. Excluding Libya, the effective income tax expense and benefit rates would be an expense of 5% and a benefit of 35% for the first nine months of 2017 and 2016.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



In the U.S. we expect to be in a cumulative loss position in 2017, and as a result we have placed a full valuation allowance on our net federal deferred tax assets. In the third quarter and first nine months of 2017 this valuation allowance was $228 million and $361 million. During 2017 we expect to realize no tax benefit on any net federal deferred tax assets generated. See Deferred Tax Assets section below for further detail.
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. The estimated realizability of the benefit of our deferred tax asset is assessed considering a preponderance of evidence. This assessment requires analysis of all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies. Negative evidence includes losses in recent years as well as the forecasts of future income (loss) in the realizable period. As of the fourth quarter of 2016, we expected to be in a cumulative loss position in 2017, which constitutes significant objective negative evidence as to the future realizability of the value of our federal deferred tax assets. Due to this negative evidence, we placed a full valuation allowance on our net federal deferred tax assets in the fourth quarterU.S.
The following items caused the effective income tax rates to be different from our U.S. statutory tax rate of 201621% for 2020 and expect2019:
•For the three and six months ended June 30, 2020, the income tax rate was reduced below the statutory rate due to realize no tax benefitthe valuation allowance on anyour net federal deferred tax assets in the U.S., which resulted in no federal tax benefit on the U.S. loss.
•For the three and six months ended June 30, 2019, the mix of pre-tax income in our international operations reduced the annual effective tax rate below the statutory tax rate. Income tax rates for the six months ended June 30, 2019 were also 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 six months of 2019. Excluding these discrete adjustments, the effective income tax rate for the first six months of 2019 was an expense of 13%.
In the first quarter of 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 were classified as short term. Subsequent to June 30, 2020, we received an $89 million cash refund related to these alternative minimum tax credits and interest.
8. Credit Losses
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 2017.this group include numerous large, mid-size and small oil and gas exploration and production companies.
14
MARATHON OIL CORPORATION
10.Notes to Consolidated Financial Statements (Unaudited)
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 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 six months ended were as follows: 
(In millions)June 30, 2020
Beginning balance as of January 1$11 
Cumulative-effect adjustment12 
Current period provision(a)
6 
Recoveries of amounts previously written off(6)
Ending balance as of June 30$23 
(a)For the six months ended June 30, 2020, the current period provision increased by $7 million in joint interest receivables and decreased by $1 million in trade receivables.
9. Inventories
        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 volatility and future decline in crude oil and natural gas prices could affect the value of our inventories and result in future impairments.
(In millions)June 30, 2020December 31, 2019
Crude oil and natural gas$9  $10  
Supplies and other items68  62  
Inventories$77  $72  
 September 30, December 31,
(In millions)2017 2016
Crude oil and natural gas$9
 $6
Supplies and other items123
 130
Inventories$132
 $136

11.10. Property, Plant and Equipment net of Accumulated Depreciation, Depletion and Amortization
(In millions)June 30, 2020December 31, 2019
United States$15,899  $16,427  
International449  493  
Corporate76  80  
Net property, plant and equipment$16,424  $17,000  
 September 30, December 31,
(In millions)2017 2016
United States E&P$15,783
 $14,158
International E&P1,772
 2,470
Corporate90
 99
Net property, plant and equipment$17,645

$16,727


Our Libya operations have been interrupted in recent years due to civil unrest. On September 14, 2016, Force Majeure was lifted and production resumed in October 2016 at our Waha concession. During December 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued during the first nine months of 2017, except for a brief interruption in March 2017 due to civil unrest.
As of September 30, 2017, our net property, plant and equipment investment in Libya is $764 million, and total proved reserves (unaudited) in Libya as of December 31, 2016 are 206 million barrels of oil equivalent (“mmboe”). 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 $764 million by a significant amount.
ExploratoryWe had 0 exploratory well costs capitalized greater than one year after completion of drilling were $32 million and $118 million as of SeptemberJune 30, 20172020 and December 31, 2016.2019.
11. Impairments
        During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. The decreasedecreased demand, when coupled with an oversupplied market, caused a corresponding deterioration in costshydrocarbon prices. We reviewed our long-lived assets for indicators of $86 millionimpairment during the first nine monthsquarter by conducting a sensitivity analysis of 2017 was primarily duethe most impactful inputs to $64 milliontheir undiscounted cash flows, including commodity prices, capital spend and reductions in exploratory well costs being expensed as a resultproduction volumes to correspond with lower capital spending. Our review concluded that the carrying amounts of our agreement to selllong-lived assets are recoverable; however, further deterioration or a more sustained decline of commodity prices may result in impairment charges in future periods. 

        We also reviewed our Diaba License G4-223equity method investments for indicators of impairment. Equity method investments are assessed for impairment whenever changes in the Republicfacts and circumstances indicate a loss in value may have occurred. When a loss in value occurs that is deemed other than temporary, the carrying value of Gabon in August of 2017, see Note 6 for further information about the divestment of certain non-core properties in our International E&P segment. Additionally, in April 2017 we received approval by the host government inequity method investment is written down to fair
15
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


value. Our first quarter review concluded that any potential losses in values of our equity method investments were temporary because the underlying declines in both commodity prices and demand did not materially manifest until early March. However, during the second quarter of 2020, we did recognize an impairment related to one of our equity method investees as noted in the table below.


E.G.The following table summarizes impairment charges of proved properties, goodwill and equity method investments and their corresponding fair values.
Three Months Ended June 30,
 20202019
(In millions)Fair ValueImpairmentFair ValueImpairment
Long-lived assets held for use$—  $—  $19  $18  
Equity method investment$142  $152  N/A$—  
 Six Months Ended June 30,
 20202019
(In millions)Fair ValueImpairmentFair ValueImpairment
Long-lived assets held for use$—  $2  $56  $24  
Goodwill$—  $95  N/A$—  
Equity method investment$142  $152  N/A$—  
•2020– During the second quarter of 2020, the continuation of the depressed commodity prices caused us to develop Block D offshore E.G. through unitizationperform a review of our equity method investments. Our review concluded that a loss of our investment value in one of our equity method investees was other than temporary. We recorded an impairment of $152 million based on the difference between our carrying value and the fair value of our investment. Our remaining investments in equity method investees did not experience losses in value that caused the fair values to be below their carrying values.
We estimated the fair value of our equity method investment using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair value was based on significant inputs not observable in the market, such as the amount of gas processed by the plant, future commodity prices, forecasted operating expenses, discount rate, and estimated cash returned to shareholders. Collectively, these inputs represent Level 3 measurements.
The impairment was recognized in income (loss) from equity method investments in our consolidated statements of income. The impairment caused us to incur a basis differential between the net book value of our investment and the amount of our underlying share of equity in the investee’s net assets. The amount of this basis differential is $126 million and will be accreted into income over the next 6.5 years, which is consistent with the Alba field resultingremaining useful life of the investee’s primary assets.
Impairments for the six months ended June 30, 2020 also included $95 million of goodwill impairment in $22the International reporting unit. See Note 14 for further information.
•2019– During the six months ended June 30, 2019, we recorded proved property impairments of $24 million, exploratory wellas a result of the anticipated sales proceeds for certain non-core proved properties in our United States segment and the 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 associated with the Corona well no longer being deferred.to sell which resulted in a Level 2 classification. See Note 4 for further information.
16

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
12. Asset Retirement Obligations
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 ninesix months ended June 30 were as follows:
June 30,
(In millions)20202019
Beginning balance as of January 1$255  $1,145  
Incurred liabilities, including acquisitions2  18  
Settled liabilities, including dispositions(3) (129) 
Accretion expense (included in depreciation, depletion and amortization)6  26  
Revisions of estimates(8) 11  
Held for sale—  (864) 
Ending balance as of June 30$252  $207  
 September 30, September 30,
(In millions)2017 2016
Beginning balance$1,653
 $1,544
Incurred liabilities, including acquisitions19
 5
Settled liabilities, including dispositions(40) (61)
Accretion expense (included in depreciation, depletion and amortization)65
 60
Revisions of estimates(113) (2)
Held for sale(2) (13)
Ending balance$1,582
 $1,533
June 30, 2020
September•Ending balance includes $10 million classified as short-term at June 30, 20172020.
June 30, 2019
•Settled liabilities include 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 of $966 million associated with the sale of our U.K. business, which was partially offset by settled liabilities for dispositions primarily related to the sale of certain conventional assets in Oklahoma as well as retirementsDroshky field in the U.K. andfirst quarter of 2019. See Note 4 for discussion of the Gulf of Mexico.
divestitures in further detail.
Revisions of estimates were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.
•Ending balance includes $60$18 million classified as short-term at SeptemberJune 30, 2017.2019.
17
September 30, 2016
Settled liabilities include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.
Ending balance includes $21 million classified as short-term at September 30, 2016.

13. Impairments and Exploration Expenses
Impairments
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment in our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.
The following table summarizes impairment charges of proved properties from continuing operations:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Total impairments$201
 $47
 $205
 $48
2017 - Impairments for the three and nine months ended September 30, 2017 were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment of $136 million. Additionally, included in proved property impairments was $65 million relating to the Gulf of Mexico as a result of lower forecasted long-term commodity prices.
2016 - Impairments for the three and nine months ended September 30, 2016 consisted primarily of conventional non-core proved properties in Oklahoma as a result of lower forecasted long-term commodity prices.
See Note 6 for relevant detail regarding dispositions, Note 7 for further detail regarding segment presentation and Note 14 for fair value measurements related to impairments of proved properties and long-lived assets.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


13. Leases

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)June 30, 2020
Operating Leases:Balance Sheet Location:
Right-of-use assetOther noncurrent assets$153 
Current portion of long-term lease liabilityOther current liabilities$83 
Long-term lease liabilityDeferred credits and other liabilities$74 
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 following table summarizeslease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the componentsentire duration of exploration expenses: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$3  
20216  
20226  
20236  
20246  
Thereafter60  
Total undiscounted cash flows$87  
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2017 2016 2017 2016
Exploration Expenses       
Unproved property impairments$172
 $28
 $217
 $172
Dry well costs77
 9
 77
 24
Geological and geophysical2
 1
 3
 1
Other43
 45
 55
 92
Total exploration expenses$294
 $83
 $352
 $289
Unproved property impairmentIn 2018, we signed an agreement with an owner/lessor to construct and Dry welllease a new build-to-suit office building in Houston, Texas. The new Houston office location is expected to be completed in 2021. The lessor and other participants are providing financing for up to $380 million, to fund the estimated project costs. As of June 30, 2020, project costs
2017 - As a result of lower forecasted long-term commodity prices incurred totaled approximately $87 million, including land acquisition and construction costs. The initial lease term is five years and will commence once construction is substantially complete and the anticipated salesnew Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain non-core propertiesterms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.
In June 2020, we submitted a notice to the lessor, as the construction agent, to reduce the financing capacity to $340 million to align with our revised estimate of the project costs. We expect the reduction to become effective in August 2020.
14.  Goodwill
As of December 31, 2019, our International E&P segment, we recorded a non-cash charge of $159 million comprisedconsolidated balance sheet included goodwill of $95 million in unproved property impairments and $64 million in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of Gabon, we recorded a non-cash impairment charge of $43 million to unproved property.
2016 - Unproved property impairments for the nine months ended September 30, 2016 primarily consist of non-cash charges of $118 million as a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases.
See Note 6 for relevant detail regarding dispositions and Note 7 for further detail regarding segment presentation.

14.  Fair Value Measurements
Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 by fair value hierarchy level.
 September 30, 2017
(In millions)Level 1 Level 2 Level 3 Total
Derivative instruments, assets       
     Commodity (a)
$—
 $10
 $—
 $10
     Interest rate—
 —
 —
 —
Derivative instruments, assets$—
 $10
 $—
 $10
Derivative instruments, liabilities       
     Commodity (a)
$2
 $3
 $—
 $5
Derivative instruments, liabilities$2
 $3
 $—
 $5
(a)
Derivative instruments are recorded on a net basis in our balance sheet. See Note 15.

 December 31, 2016
(In millions)Level 1 Level 2 Level 3 Total
Derivative instruments, assets       
     Commodity (a)
$—
 $—
 $—
 $—
Interest rate—
 68
 —
 68
Derivative instruments, assets$—
 $68
 $—
 $68
Derivative instruments, liabilities       
     Commodity (a)
$—
 $60
 $—
 $60
Derivative instruments, liabilities$—
 $60
 $—
 $60
(a)
Derivative instruments are recorded on a net basis in our balance sheet. See Note 15.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Commodity derivatives include three-way collars, call options, swaps, swaptions, and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include only commodity prices 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, swaptions and call options, 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.
Historically, both our interest rate swaps and forward starting interest rate swaps were measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 15 for additional discussion of the types of derivative instruments we used.
Fair Values -International reporting unit. Goodwill
Unlike long-lived assets, goodwill must be is tested for impairment at least annually,on an annual basis, or between annual tests if an event occurswhen events or changes in circumstances change that would more likely than not reduceindicate the fair value of a reporting unit with goodwill may have been reduced below its carrying amount. Goodwill is tested for impairment atvalue. 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 level. As of September 30, 2017, we have $115 million of goodwill associated with our International E&P reporting unit. was less than its carrying value.
We estimateestimated 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
18
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
enterprise value, and valuation multiples of us and our 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 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. We performedBased on the results, we concluded our annualgoodwill was fully impaired, and recorded an impairment testof $95 million in the secondconsolidated statements of income for the first quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40%. While the fair value of our International E&P reporting unit exceeded the book value, subsequent variations in the above assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.2020.
Fair Values- Nonrecurring
June 30,
(In millions)20202019
Beginning balance as of January 1, gross$95  $97  
Less: accumulated impairments—  —  
Beginning balance, net95  97  
Dispositions—  (2) 
Impairment(95) —  
Ending balance as of June 30, net$—  $95  
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
15.  Derivatives
 Three Months Ended September 30,
 2017 2016
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets$169
 $201
 $15
 $47
 Nine Months Ended September 30,
 2017 2016
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets$169
 $205
 $15
 $48
Long-lived assets that were impaired are discussed below. The fair values of each, unless otherwise noted, were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs toFor further information regarding the fair value measurement include reserveof 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 production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life ofreported net amounts along with where they appear on the reservoir.consolidated balance sheets.
United States E&P
June 30, 2020
(In millions)AssetLiabilityNet Asset (Liability)Balance Sheet Location
Not Designated as Hedges
Commodity$100  $21  $79  Derivative assets
Total Not Designated as Hedges$100  $21  $79  
Cash Flow Hedges
Interest Rate$—  $26  $(26) Deferred credits and other liabilities
Interest Rate2  —  2  Other noncurrent assets
Total Designated Hedges$2  $26  $(24) 
Total$102  $47  $55  
In the third quarter of 2017, impairments of $65 million were recorded consisting of certain proved properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $66 million.
December 31, 2019
(In millions)AssetLiabilityNet Asset (Liability)Balance Sheet Location
Not Designated as Hedges
Commodity$9  $1  $8  Derivative assets
Commodity1  —  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  
19
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Derivatives Not Designated as Hedges
We have entered into multiple crude oil and natural gas 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, two-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. Two-way collars only consist of a sold call (ceiling) and a purchased put (floor). These crude oil and natural gas derivatives were not designated as hedges.
The following table sets forth outstanding derivative contracts as of June 30, 2020, and the weighted average prices for those contracts:
20202021
Third QuarterFourth QuarterFull 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)33,478  —  —  
Weighted average price per Bbl:
Ceiling$40.47  $—  $—  
Floor$30.98  $—  $—  
Fixed Price WTI Swaps
Volume (Bbls/day)10,000  —  —  
Weighted average price per Bbl$32.77  $—  $—  
Basis Swaps - Argus WTI Midland (a)
Volume (Bbls/day)15,000  15,000  —  
Weighted average price per Bbl$(0.94) $(0.94) $—  
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)5,000  5,000  808  
Weighted average price per Bbl$(7.24) $(7.24) $(7.24) 
NYMEX Roll Basis Swaps
Volume (Bbls/day)60,000  30,000  —  
Weighted average price per Bbl$(1.58) $(0.81) $—  
Natural Gas
Two-Way Collars
Volume (MMBtu/day)—  —  62,329  
Weighted average price per MMBtu:
Ceiling$—  $—  $3.07  
Floor$—  $—  $2.44  
Basis Swaps - WAHA / HH (c)
Volume (MMBtu/day)10,000  10,000  —  
Weighted average price per MMBtu$(0.37) $(0.37) $—  
(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 Waha and NYMEX Henry Hub.
20
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)

The following table sets forth outstanding derivative contracts entered into between July 1 and August 5, 2020, and the weighted average prices for those contracts:
In
20202021
Third QuarterFourth QuarterFull Year
Crude Oil
NYMEX WTI Two-Way Collars
Volume (Bbls/day)3,261  10,000  10,000  
Weighted average price per Bbl:
Ceiling$48.00  $48.65  $52.37  
Floor$36.50  $37.00  $35.00  
Natural Gas
Two-Way Collars
Volume (MMBtu/day)66,304  150,000  50,000  
Weighted average price per MMBtu:
Ceiling$2.49  $2.62  $2.93  
Floor$2.00  $2.13  $2.40  
NGL
Fixed Price Ethane Swaps
Volume (MMBtu/day)7,304  10,000  —  
Weighted average price per Bbl$8.78  $8.78  $—  
The mark-to-market impact and settlement of our commodity derivative instruments appears in the third quartertable below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of 2016, impairmentsincome.
Three Months Ended June 30,Six Months Ended June 30,
(In millions)2020201920202019
Mark-to-market gain (loss)$(96) $11  $75  $(102) 
Net settlements of commodity derivative instruments$26  $5  $57  $27  
Derivatives Designated as Cash Flow Hedges
During 2020, we entered into forward starting interest rate swaps with a notional amount of $47$500 million were recorded primarily consistingto hedge variations in cash flows arising from fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of conventional non-core proved propertiesa future debt issuance in Oklahoma as2022; and an additional $300 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 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 June 30, 2020, we entered into additional forward starting interest rate swaps with a resultnotional amount of lower forecasted long-term commodity prices,$50 million and a weighted average rate of 0.90% to an aggregatehedge variations in cash flows related to the same LIBOR interest rate 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 13for further details regarding the lease of the new Houston office.
21
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.
June 30, 2020December 31, 2019
Maturity Date
Aggregate Notional Amount
(in millions)
Weighted Average, LIBOR
Aggregate Notional Amount
(in millions)
Weighted Average, LIBOR
November 1, 2022$500  0.99 %$—  — %
June 1, 2025$300  0.96 %$—  — %
September 9, 2026$320  1.51 %$320  1.51 %
At June 30, 2020, accumulated other comprehensive income included deferred losses of $24 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.
16. Fair Value Measurements
Fair Values – Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of $15 million.June 30, 2020 and December 31, 2019 by hierarchy level.
International E&P
June 30, 2020
(In millions)Level 1Level 2Level 3Total
Derivative instruments, assets
Commodity(a)
$—  $88  $—  $88  
Interest rate—  2  —  2  
Derivative instruments, assets$—  $90  $—  $90  
Derivative instruments, liabilities
Commodity(a)
$(9) $—  $—  $(9) 
Interest rate—  (26) —  (26) 
Derivative instruments, liabilities$(9) $(26) $—  $(35) 
Total$(9) $64  $—  $55  
In the third quarter of 2017, we
 December 31, 2019
(In millions)Level 1Level 2Level 3Total
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 proved property impairments of $136 million, to an aggregateon a net basis in our consolidated balance sheet. See Note 15.
Commodity derivatives include three-way collars, two-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. These instruments are measured at fair value of $103 million, on certain non-core properties in our International E&P segment primarily asusing either a result of lower forecasted long-termBlack-Scholes or a modified Black-Scholes Model. For swaps, inputs to the models include only commodity prices and interest rates and are categorized as a resultLevel 1 because all assumptions and inputs are observable in active markets throughout the term of the anticipated salesinstruments. For three-way collars and two-
22
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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 certain non-core international assets. 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 11for detail on our fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe. This resulted in a Level 2 classification. See Note6 for further information about the divestment of certain non-core properties in our International E&P segment.
Canadian discontinued operations
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note6 for relevant detail regarding dispositions.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 SeptemberJune 30, 20172020 and December 31, 2016.
2019.
September 30, 2017 December 31, 2016
Fair Carrying Fair CarryingJune 30, 2020December 31, 2019
(In millions)Value Amount Value Amount(In millions)Fair ValueCarrying AmountFair ValueCarrying Amount
Financial assets       Financial assets    
Current assets (a)
$755
 $754
 $7
 $7
Current assetsCurrent assets$4  $4  $4  $4  
Other noncurrent assets127
 128
 105
 108
Other noncurrent assets28  44  26  38  
Total financial assets $882
 $882
 $112
 $115
Total financial assets$32  $48  $30  $42  
Financial liabilities 
  
  
  
Financial liabilities    
Other current liabilities$44
 $55
 $68
 $75
Other current liabilities$61  $97  $62  $90  
Long-term debt, including current portion (b)
6,781
 6,527
 7,449
 7,292
Long-term debt, including current portion(a)
Long-term debt, including current portion(a)
5,558  5,530  6,174  5,529  
Deferred credits and other liabilities112
 105
 114
 107
Deferred credits and other liabilities105  84  99  86  
Total financial liabilities $6,937
 $6,687
 $7,631
 $7,474
Total financial liabilities$5,724  $5,711  $6,335  $5,705  
(a)    Includes our two notes receivable relating to the sale of our Canadian business as of September 30, 2017, see note 6 for further information.
(b)Excludes capital leases, debt issuance costs and interest rate swap adjustments.costs.
Fair values of our notes receivable and 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.
MostAll 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 suchour debt. The fair value of our debt that is not publicly traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



15. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 14. All of our commodity derivatives and historical interest rate 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.
 September 30, 2017  
(In millions)Asset Liability Net Asset (Liability) Balance Sheet Location
Not Designated as Hedges       
   Commodity$10
 $1
 $9
 Other current assets
   Commodity—
 4
 (4) Deferred credits and other liabilities
Total Not Designated as Hedges$10
 $5
 $5
  
     Total$10

$5
 $5
  
 December 31, 2016  
(In millions)Asset Liability Net Asset (Liability) Balance Sheet Location
Fair Value Hedges       
     Interest rate$3
 $—
 $3
 Other current assets
     Interest rate1
 —
 1
 Other noncurrent assets
Cash Flow Hedges       
     Interest rate$64
 $—
 $64
 Other noncurrent assets
Total Designated Hedges$68
 $—
 $68
  
        
Not Designated as Hedges       
     Commodity$—
 $60
 $(60) Other current liabilities
Total Not Designated as Hedges$—
 $60
 $(60)  
     Total$68
 $60
 $8
  

Derivatives Designated as Fair Value Hedges
During the third quarter of 2017, we terminated all of our interest rate swaps designated as fair value hedges. The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income has a gross impact that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value hedges in all periods presented.
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.
 September 30, 2017 December 31, 2016
 Aggregate Notional AmountWeighted Average, LIBOR Aggregate Notional AmountWeighted Average, LIBOR
Maturity Dates(in millions)Floating Rate (in millions)Floating Rate
October 1, 2017$—
—% $600
5.10%
March 15, 2018$—
—% $300
5.04%

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Derivatives Not Designated as Hedges
Interest Rate Swaps
During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow hedges. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. See Note 17 for further detail. As a result, we terminated our forward starting interest rate swaps receiving proceeds of $54 million. We recognized a gain of $47 million, of which $46 million is related to deferred gains reclassified from accumulated other comprehensive income, in net interest and other in the third quarter of 2017.
The following table presents, by maturity date, information about our terminated forward starting interest rate swap agreements, including the rate.
 September 30, 2017 December 31, 2016
 Aggregate Notional AmountWeighted Average, LIBOR Aggregate Notional AmountWeighted Average, LIBOR
Maturity Dates(in millions)Fixed Rate (in millions)Fixed Rate
March 15, 2018$—
—% $750
1.57%
The following table sets forth the net impact of the terminated forward starting interest rate swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2017 2016 2017 2016
Interest Rate Swaps       
  Beginning balance$46
 $—
 $60
 $—
Change in fair value recognized in other comprehensive income—
 2
 (13) 2
Reclassification from other comprehensive income(46) —
 (47) —
  Ending balance$—
 $2
 $—
 $2
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Commodity Derivatives
We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States E&P sales through December 2018. These commodity derivatives consist of three-way collars, swaps, swaptions, basis swaps, and call options. 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 September 30, 2017 and the weighted average prices for those contracts:
Crude Oil
 20172018
 Fourth QuarterFirst QuarterSecond QuarterThird QuarterFourth Quarter
Three-Way Collars (a)





Volume (Bbls/day)50,00075,00075,00062,00062,000
Weighted average price per Bbl:




Ceiling$60.37$56.24$56.24$56.08$56.08
Floor$54.80$51.33$51.33$50.50$50.50
Sold put$47.80$44.73$44.73$43.61$43.61
Swaps (b)(c)





Volume (Bbls/day)20,000————
Weighted average price per Bbl$51.37————
Sold call options (d)





Volume (Bbls/day)35,000————
Weighted average price per Bbl$61.91————
Basis Swaps (e)





Volume (Bbls/day)—5,0005,00010,00010,000
Weighted average price per Bbl—$(0.60)$(0.60)$(0.67)$(0.67)
(a)
Between September 30, 2017 and October 30, 2017, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $58.07, a floor price of $53.70, and a sold put price of $47.00.
(b)
The counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $52.67 per Bbl indexed to NYMEX WTI, which is exercisable on December 29, 2017. If the counterparties exercise, the term of the fixed-price swaps would be from January - June 2018 and, if all such options are exercised, for 10,000 Bbls/day.
(c)
Between September 30, 2017 and October 30, 2017, we entered into 40,000 Bbls/day of fixed-price swaps for November - December 2017 with a weighted average price of $54.11.
(d)
Call options settle monthly.
(e)
The basis differential price is between WTI Midland and WTI Cushing.
Natural Gas
 20172018
 Fourth QuarterFirst QuarterSecond QuarterThird QuarterFourth Quarter
Three-Way Collars




Volume (MMBtu/day)120,000200,000160,000160,000160,000
Weighted average price per MMBtu:




Ceiling$3.71$3.79$3.61$3.61$3.61
Floor$3.14$3.08$3.00$3.00$3.00
Sold put$2.60$2.55$2.50$2.50$2.50
Swaps




Volume (MMBtu/day)20,000————
Weighted average price per MMBtu$2.93————
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)




The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three and nine month periods ended September 30, 2017 and 2016, respectively. The three and nine month periods ended September 30, 2017 impact was a net loss of $22 million and a net gain $115 million compared to a net gain of $42 million and a net loss of $48 million for the same respective period in 2016. Net settlements of commodity derivative instruments for the three and nine month periods ended September 30, 2017 were gains of $34 million and $51 million compared to gains of $17 million and $41 million for the respective period in 2016.

16.    Incentive Based Compensation
Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the first nine months of 2017: 
 Stock Options Restricted Stock Awards & Units
 
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 201611,915,533
 
$27.71
 6,933,533
 
$14.44
Granted799,591
(a) 

$15.80
 4,062,520
 
$16.20
Options Exercised/Stock Vested(8,666) 
$7.22
 (2,254,525) 
$17.76
Canceled(2,298,820) 
$33.32
 (946,431) 
$15.16
Outstanding at September 30, 201710,407,638
 
$25.57
 7,795,097
 
$14.31
(a)    The weighted average grant date fair value of stock option awards granted was $6.07 per share.
Stock-based performance unit awards
 During the first nine months of 2017, we granted 563,631 stock-based performance units to certain officers. The grant date fair value per unit was $17.75.

17. Debt
Revolving Credit Facility
As of SeptemberJune 30, 2017,2020, we had no0 borrowings against our $3.4$3.0 billion unsecured revolving credit facility (the “Credit(“Credit Facility”), as described below.
In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. 
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. If anIn the event of a 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 the cash collateralization of all outstanding letters of credit under the Credit Facility. As of SeptemberJune 30, 2017,2020, we were in compliance with this covenant with a debt-to-capitalization ratio of 36%33%.
Long-term debt
23
On July 24, 2017, we issued $1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the senior unsecured notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior unsecured notes at any time at the applicable redemption price, plus accrued interest, if any. During the third quarter of 2017, we used the net proceeds of $990 million plus existing cash on hand to redeem the following senior unsecured notes:
$682 million 6.0% Notes Due in 2017
$854 million 5.9% Notes Due in 2018
$228 million 7.5% Notes Due in 2019
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Long-term debt

At June 30, 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.

18. Stockholders’ Equity
During the third quartersix months ended June 30, 2020, we acquired approximately 9 million common shares at a cost of 2017,$85 million, which were held as treasury stock. Including these repurchases, the total remaining share repurchase authorization was $1.3 billion at June 30, 2020. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.
19. Incentive Based Compensation
Stock options, restricted stock awards and restricted stock units
The following table presents a resultsummary of activity for the first six months of 2020: 
 Stock OptionsRestricted Stock Awards & Units
Number of SharesWeighted Average Exercise PriceAwardsWeighted Average Grant Date Fair Value
Outstanding at December 31, 20195,659,731   $23.55  7,174,386  $15.88  
Granted1,132,808  
(a)
$10.47  5,337,796  $8.55  
Exercised/Vested(52,333) $7.22  (2,911,712) $15.93  
Canceled(b)
(565,219) $23.52  (1,405,754) $11.70  
Outstanding at June 30, 20206,174,987   $21.29  8,194,716  $11.80  
(a)The weighted average grant date fair value of stock option awards granted was $3.82 per share.
(b)Included in canceled are forfeitures related to workforce reductions.
Stock-based performance unit awards
        During the first six months of 2020, we granted 1,038,676 stock-based performance units to certain officers to be settled in shares. The grant date fair value per unit was $10.55, as calculated using a Monte Carlo valuation model. As of June 30, 2020 there were 1,658,088units outstanding.
20. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost (credit):
Three Months Ended June 30,
Pension BenefitsOther Benefits
(In millions)2020
2019(d)
20202019
Service cost$5  $5  $—  $—  
Interest cost2  7  —  1  
Expected return on plan assets(2) (8) —  —  
Amortization:    
– prior service cost (credit)(2) (2) (5) (4) 
– actuarial loss2  2  1  —  
Net settlement loss(a)
14  2  —  —  
Net curtailment gain(b)
(3) —  (14) —  
Net periodic benefit cost (credit)(c)
$16  $6  $(18) $(3) 
24
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Six Months Ended June 30,
Pension BenefitsOther Benefits
(In millions)2020
2019(d)
20202019
Service cost$10  $9  $—  $—  
Interest cost5  14  1  2  
Expected return on plan assets(5) (16) —  —  
Amortization:
– prior service cost (credit)(4) (4) (9) (8) 
– actuarial loss5  4  1  —  
Net settlement loss(a)
16  2  —  —  
Net curtailment gain(b)
(3) —  (14) —  
Net periodic benefit cost (credit)(c)
$24  $9  $(21) $(6) 

(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.
(c)Net periodic benefit cost (credit) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
(d)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 above redemptionU.K. asset on July 1, 2019.

        During the first six months of $1.76 billion in senior unsecured notes,2020, we recognized a loss on early extinguishmentmade contributions of debt$12 million to our funded pension plan and expect to contribute an additional $16 million this year. During the first six months of $46 million, primarily due to make-whole call provisions. In connection with the redemption2020, we made payments of the senior unsecured notes, we terminated our forward starting interest rate swaps, which resulted in proceeds of $54$14 million and a gain of approximately $47$8 million into earnings in the third quarter of 2017. See Note 15 for further detail on our forward starting interest rate swaps.related to unfunded pension plans and other postretirement benefit plans.

18.21. Reclassifications Out of Accumulated Other Comprehensive LossIncome (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:income (loss):
Three Months Ended June 30,Six Months Ended June 30,
(In millions)2020201920202019Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit$7  $6  $13  $12  Other net periodic benefit credit
Amortization of actuarial loss(3) (2) (6) (4) Other net periodic benefit credit
Net settlement loss(14) (2) (16) (2) Other net periodic benefit credit
Net curtailment gain17  —  17  —  Other net periodic benefit credit
Total reclassifications to expense, net of tax (a)
$7  $2  $8  $6  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.

 Three Months Ended September 30, Nine Months Ended September 30,  
(In millions)2017 2016 2017 2016 Income Statement Line
    
Postretirement and postemployment plans        
Amortization of actuarial loss$(3) $(4) $(7) $(11) General and administrative
Net settlement loss(8) (14) (25) (93) General and administrative
Derivative hedges         
Recognized gain on terminated derivative hedge46
 —
 46
 —
 Net interest and other
Ineffective portion of derivative hedge—
 —
 1
 —
 Net interest and other
 35
 (18) 15
 (104) Income (loss) from operations
 (40) 6
 (40) 38
 (Provision) benefit for income taxes
Total reclassifications to expense, net of tax(5) (12) (25) (66) Income (loss) from continuing operations
Foreign currency hedges         
Net recognized loss in discontinued operations, net of tax—
 —
 (30) —
 Income (loss) from discontinued operations
Total reclassifications to expense$(5) $(12) $(55) $(66) Net income (loss)

19. 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 $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our capital program.

20.22. Supplemental Cash Flow Information
 Six Months Ended June 30,
(In millions)20202019
Included in operating activities:  
Interest paid, net of amounts capitalized$126  $128  
Income taxes paid to taxing authorities, net of refunds received (a)
4  66  
Noncash investing activities:  
Increase (decrease) in asset retirement costs$(6) $29  
Asset retirement obligations assumed by buyer (b)
—  109  
(a)The six months ended June 30,2020 and 2019 includes $4 million and $89 million, related to tax refunds.
(b)In 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), including our $98 million asset retirement obligation and the
25
 Nine Months Ended September 30,
(In millions)2017 2016
Net cash (used in) operating activities:   
Interest paid (net of amounts capitalized)$(269) $(243)
Income taxes paid to taxing authorities(101) (68)
Noncash investing activities, related to continuing operations: 
  
Changes in asset retirement costs$(94) $3
Asset retirement obligations assumed by buyer14
 86
Increase in capital expenditure accrual207
 —
Notes receivable for disposal of assets745
 —

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


sale of our non-operated interest in the Atrush block in Kurdistan.


21.        Other noncash investing activities include accrued capital expenditures for the six months ended June 30, 2020 and 2019 of $48 million and $300 million.
23. Equity Method Investments
During the periods ended June 30, 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 June 30, 2020June 30, 2020December 31, 2019
EGHoldings60%$139  $310  
Alba Plant LLC52%168  163  
AMPCO45%169  190  
Total $476  $663  
In the second quarter of 2020, we recorded an impairment of $152 million to an investment in an equity method investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.
Summarized financial information for equity method investees is as follows:
Three Months Ended June 30,Six Months Ended June 30,
(In millions)2020201920202019
Income data:
Revenues and other income$111  $233  $283  $453  
Income (loss) from operations(10) 82  (40) 131  
Net income (loss)(13) 63  (39) 95  

Revenues from related parties were $10 million and $20 million for the three and six months ended June 30, 2020 and $11 million and $21 million for the three and six months ended June 30, 2019 with the majority related to EGHoldings in all periods.
Current receivables from related parties at June 30, 2020 were $25 million with the majority related to EGHoldings and $28 million at December 31, 2019 with the majority related EGHoldings and Alba Plant LLC. Payables to related parties at June 30, 2020 were $10 million with the majority related to EGHoldings and $11 million for December 31, 2019 with the majority related to Alba Plant LLC.
24. Commitments and Contingencies
The U.K. tax authorities have challengedIn the timingsecond quarter of deductibility for certain Brae area decommissioning costs which we claimed for U.K. corporation tax purposes.  The dispute relates2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to the timingprocess third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. Our equity method investee, Alba Plant LLC, is also a party to some of the deductionagreements. These agreements contain clauses that require MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and doesdamage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant and certain environmental liabilities resulting from the actions or inaction by Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental liabilities, 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 disputehave any history of prior indemnification claims, as completion of the general deductibilityplant modifications is not expected to finish until
26
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
2021, and as such, we do not have any history of decommissioning costs. In July 2017,environmental discharge or contamination. Therefore, we have not recorded a hearing took place at the U.K.’s First-tier Tribunalliability with respect to this tax deduction.  Ifthese indemnities 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. Two separate guarantees were executed during the second quarter of 2020; one for a maximum of $91 million pertaining to the payment obligations of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining to the payment obligations of Alba Plant LLC.  Payment by us would be required if either of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027.  We measured these guarantees at fair value using the net present value of premium payments we expect to receive from our investees. We recorded a liability for these guarantees of $4 million as of June 30, 2020, with a corresponding receivable from our investees. Each of Equatorial Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.
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 June 30, 2020, we have a $101 million current liability in suspended royalty and working interest revenue, including interest, and have a long-term receivable of $25 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 prevail in the Tribunal, we may be required to adjust the timing of our tax deduction and make a payment to the U.K. tax authorities of approximately $130 million, which would be recovered as future decommissioning activities are performed and deductions claimed. We estimate that any revisions to current and deferred tax liabilities, if we do not prevail,believe these enforcement actions would have no cumulativea material adverse earnings impacteffect on our consolidated financial position, results of operations.  While we believe that it is more likely than not that we will prevail in the Tribunal, if we do not, we have the option to seek appeal. 
We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. These audits have been completed through the 2014 tax year, except for tax years 2010 and 2011. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we intend to file a Tax Court Petition in the fourth quarter of 2017.  We believe that it is more likely than not that we will prevail.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 reflected inoffset by the prices ofwe 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.

27



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Outlook
Operations
Market Conditions
Results of Operations
Critical Accounting Estimates
Accounting Standards Not Yet Adopted
Cash Flows
Liquidity and Capital Resources
Environmental Matters and Other Contingencies
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 1.1.
Executive Overview
We are an independent exploration and production company based in Houston, Texas focused onTexas. Our strategy is to deliver competitive and improving corporate level returns by focusing our capital investment in the lower cost, higher margin U.S. unconventional resource plays with operations(the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico).
        Commodity prices declined substantially in the United States, Africafirst half of 2020. While commodity prices are likely to remain volatile, we believe we can manage through this lower commodity price macro environment as our portfolio affords us the flexibility to respond to changing market conditions. Our primary focus remains on protecting our balance sheet and Europe. Total proved reserves were 1.4 billion boe at December 31, 2016, excludingmaintaining a strong liquidity position. We believe our Canadianfinancial strength, quality portfolio, and ongoing focus on reducing our cost structure better position us to navigate during this unprecedented time.
The risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and total assets were $22.9 billion at September 30, 2017.
As discussed in Note 6safety, the vast majority of our corporate workforce works remotely as we plan a process for a phased return of employees to the consolidated financial statements,office. Working remotely has not significantly impacted our ability to maintain operations, has allowed our field offices to operate without any disruption, and has not caused us to incur significant additional expenses; however, we closed onare unable to predict the saleduration or ultimate impact of our Canadian business, which has been reflected as discontinued operations and is excluded from operations in all periods presented.these measures.

Key highlights include the following:
LiquidityMaintained focus on balance sheet and corporate financingliquidity
•At the end of the thirdsecond quarter of 2017,2020, we had $5.2approximately $3.5 billion of liquidity, comprised of $1.8an undrawn $3.0 billion revolving credit facility and $0.5 billion in cash, and no significant near-term debt maturities. We remain investment grade at all three primary rating agencies, with recent reviews by all three primary rating agencies.
•Continued our capital discipline, with an undrawn $3.4 billion revolving credit facility.additional reduction of our Capital Budget to $1.2 billion.
•Restructured a portion of our commodity derivative portfolio during the quarter, which minimized the near-term crude downside and protected basis differentials.
•Continued to opportunistically execute additional commodity derivatives to minimize the risk of price fluctuations.
•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 Directors compensation through year-end, and U.S. employee and contractor workforce reductions.
•Temporarily suspended the quarterly dividend and share repurchases to maximize liquidity.
•In early July of 2017, we expanded the capacity of the revolving credit facility from $3.3 billion2020, collected an $89 million cash refund related to $3.4 billion.alternative minimum tax credits and associated interest.
In the third quarter of 2017, we issued $1 billion of 4.4% senior unsecured notes due in 2027 and redeemed approximately $1.8 billion of debt due in 2017, 2018 and 2019. This offering and redemption reduced total long-term debt by $775 million and reduced annual interest expense by approximately $60 million.
Simplifying our portfolio
We entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments.
28

We closed on the sale of certain conventional non-core assets in Oklahoma, with sales volumes of 2 mboed in the third quarter of 2017, for proceeds of $25 million resulting in a pre-tax gain of $21 million.
Financial and Operationaloperational results
Total•U.S. net sales volumes from continuing operations are 409decreased by 7% to 308 mboed, including Libya, which is 20% highera 4% reduction in U.S. crude oil net sales volumes compared to the same quarter last year. This includes an 18% increase in sales volumes from the U.S resource plays to 227 mboed within our United States E&P segment.
Wells to sales in the first nine months of 2017 increased over 35% in the U.S. resource plays in our United States E&P segment.
Cash provided by operating activities from continuing operations of $1,487 million for the first nine months of 2017 is primarilyyear as a result of increasedoverall lower wells to sales volumes,activity driven by the lower unit production expensedrilling and improved capital efficiency.completions activity.
•Our net loss per share from continuing operations was $0.70$0.95 in the thirdsecond quarter of 20172020 as compared to a net lossincome per share of $0.24$0.20 in the same period last year. Included in our financial results for the thirdcurrent quarter:
◦Revenues from contracts with customers decreased $891 million compared to the same quarter 2017last year, largely due to lower price realizations and decreased production volumes. Average crude oil price realizations decreased by 64% during the first six months of 2020 as compared to the first six month of 2019.
◦Net loss on commodity derivatives of $70 million for the second quarter of 2020, an $86 million decrease from the same period in 2019, which was a net loss are:
◦An increase in sales and other operating revenues of approximately 40% to $1,114 million, including a commodity derivative net loss of $22 million compared to a net gain of $42 million in the comparable quarter last year.
◦Production expense in our United States E&P segment increased 7% while our sales volumes increased 13%. In our International E&P segment, production expense increased $26 million primarily due to timing of our U.K. liftings.

gain of $16 million.

◦Exploration and impairment expenses increased a combined $365 million to $495 million primarily due to non-cash impairment charges on proved and unproved properties as a result of the anticipated sales of certain non-core international assets and due to lower forecasted long-term commodity prices.
◦Loss on early extinguishment of debt of $46 million was offset by a gain on the termination of interest rate swaps of $47 million, in net interest and other, as a result of the issuance and redemption of debt in the third quarter 2017.
◦Our provision for income taxes was $141 million in the third quarter of 2017 compared to a benefit of $107 million in the same quarter last year primarily resulting from tax expense in Libya due to the resumption of production and no tax benefit due to the full valuation allowance on our net federal deferred tax assets in the current quarter.

◦A non-cash impairment of an investment in one of our equity method investees of $152 million.
•Net cash provided by operating activities in the first six months of 2020 decreased to $710 million or 46% primarily as a result of lower commodity price realizations, compared to the first six months of 2019.
•The June 30, 2020 cash balance reflects a decrease of approximately $336 million from year-end, due in part to working capital changes reflecting the slowdown of 2020 capital activity.
Outlook
Capital Budget
        Earlier this year, we announced an approved 2020 Capital Budget of $2.4 billion, including $200 million to fund resource play leasing and exploration (“REx”). In light of the substantial decline in commodity prices and oversupply in the market, our Board of Directors approved a reduction to our Capital Budget earlier in the year to a level of $1.3 billion. Due to strong execution and capital efficiency improvement, in August we further reduced our full year 2020 capital spending budget to $1.2 billion. This revised Capital Budget represents a 50% reduction of our original budget. The revised budget contemplates a full suspension of our Oklahoma activity in 2020, a decrease in Northern Delaware drilling activity, and a continued optimization of our development plans in the Bakken and Eagle Ford. This also completes our REx drilling program for 2020. Additional adjustments to capital spending plans may be necessary in the future to respond to the shifts in the macro environment.

Commensurate with our revised budget of $1.2 billion for 2020, we believe our full year production volumes will be between 370 mboed to 384 mboed.
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to the following Results of Operations section for a price-volume analysis for each of the segments.
Three Months Ended June 30,Six Months Ended June 30,
Net Sales Volumes20202019Increase (Decrease)20202019Increase (Decrease)
United States (mboed)
308  330(7)%323  3143 %
International (mboed)(a)
84  107(21)%83  98(15)%
Total (mboed)
392  437(10)%406  412(1)%
 Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes2017 2016 Increase (Decrease) 2017 2016 Increase
(Decrease)
United States E&P (mboed)
244 216 13% 225 226 —%
International E&P (a) (mboed)
165 126 31% 142 114 25%
Total Continuing Operations (mboed)
409 342 20% 367 340 8%
(a)
Three and nine months ended September 30, 2017 includes net sales volumes relating to Libya of 23 and 15 mboed, respectively.

(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 six months ended June 30, 2019 includes net sales volumes related to the U.K. of 11 mboed. See Note 4 to the consolidated financial statements for further information.
United States E&P

Net sales volumes in the segment were lower in the second quarter of 2020 but higher in the thirdfirst six months of 2020 as compared to their respective 2019 periods. In the second quarter 2017 primarily asof 2020, we began the process of transitioning to a resultsignificantly lower level of newdrilling and completion activity across our domestic portfolio. This lower pace of activity had the biggest effect in Oklahoma, where we did not bring any wells to sales across all U.S. resource plays,during the quarter and experienced a significant decline in production. Overall sales volumes increased in the first six months of 2020 due to an increase in the absolute number of producing wells since June 30, 2019, primarily in the Bakken and Eagle Ford.
29

We expect that our planned pace of drilling and completions activity during the second half of the year will enable us to  meet our 2020 production guidance as well as our acquisitionnoted in Northern Delaware.the preceding Outlook section. The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
Three Months Ended June 30,Six Months Ended June 30,
Net Sales Volumes20202019Increase (Decrease)20202019Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford108  109  (1)%111  107  4 %
Bakken103  103  — %106  98  8 %
Oklahoma60  82  (27)%67  72  (7)%
Northern Delaware30  27  11 %30  27  11 %
Other United States7  9  (22)%9  10  (10)%
Total United States308  330  (7)%323  314  3 %
Three Months Ended June 30, 2020
Sales Mix - U.S. Resource PlaysEagle FordBakkenOklahomaNorthern DelawareTotal
Crude oil and condensate61 %78 %26 %54 %60 %
Natural gas liquids18 %12 %28 %21 %18 %
Natural gas21 %10 %46 %25 %22 %
Three Months Ended June 30,Six Months Ended June 30,
Drilling Activity - U.S. Resource Plays2020201920202019
Gross Operated
Eagle Ford:
Wells drilled to total depth9  36  41  66  
Wells brought to sales20  41  58  82  
Bakken:
Wells drilled to total depth8  20  35  32  
Wells brought to sales8  30  33  59  
Oklahoma:
Wells drilled to total depth—  18  9  38  
Wells brought to sales—  18  13  36  
Northern Delaware:
Wells drilled to total depth3  14  15  27  
Wells brought to sales6  16  12  31  
 Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes (a)2017 2016 Increase (Decrease) 2017 2016 Increase
(Decrease)
Equivalent Barrels (mboed)
           
Oklahoma Resource Basins58 41 41% 50 32 56%
Eagle Ford101 97 4% 100 109 (8)%
Bakken59 54 9% 52 55 (5)%
Northern Delaware9 — 100% 4 — 100%
Other United States (b)
17 24 (29)% 19 30 (37)%
Total United States E&P244 216 13% 225 226 —%
(a)
Our U.S. Resource plays consists of the Oklahoma Resource Basins, Eagle Ford, Bakken and Northern Delaware.
(b) Three and nine months ended September 30, 2017 includes a net sales volume reduction from September 30, 2016 of 7 mboed and 17 mboed, respectively, primarily consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further disposition information.


 Three Months Ended September 30, 2017
Sales Mix - U.S. Resource PlaysOklahoma Resource Basins Eagle Ford Bakken Northern Delaware Total
Crude oil and condensate29% 57% 83% 68% 57%
Natural gas liquids25% 22% 10% 2% 19%
Natural gas46% 21% 7% 30% 24%


 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Gross Operated - U.S. Resource Plays       
        
Oklahoma Resource Basins:       
Wells drilled to total depth27 9 65 20
Wells brought to sales15 12 47 20
Eagle Ford:       
Wells drilled to total depth43 33 141 131
Wells brought to sales36 36 124 116
Bakken:       
Wells drilled to total depth27 — 72 3
Wells brought to sales20 3 26 13
Northern Delaware       
Wells drilled to total depth11 — 13 —
Wells brought to sales5 — 7 —

Oklahoma Resource Basins – Our net sales volumes in the third quarter increased by more than 40% from the year ago quarter, with net sales volumes of 58 mboed in third quarter of 2017. During the quarter, our activity was concentrated in the STACK, and was focused on leasehold capture, additional delineation drilling and infill spacing pilots.
•Eagle Ford– Our net sales volumes were 101108 mboed in the second quarter of 2020, including oil sales of 66 mbbld and we brought 20 gross company-operated wells to sales. Given the market conditions in the second quarter, we suspended frac activities. In the third quarter of 2017 which was 4% higher compared2020, we restarted our drilling program and plan to average 2 rigs and 1 frac crew over the prior year quarter. Our sales volumes for the quarter increased as a resultsecond half of new wells to sales and our ability to safely and efficiently return the asset to pre-storm production rates following landfall of Hurricane Harvey.
2020.
•Bakken– Our net sales volumes were 59103 mboed, comparedincluding 81 mbbld of oil sales and we brought 8 gross company-operated wells to 54 mboedsales. We suspended frac activity in the prior yearsecond quarter. In the third quarter of 2017,2020, we brought 20 gross operated wellsresumed completions activities. We plan to sales across Myrmidonaverage 2 rigs and Hector, while successfully executing completion trials with strong well results.
1 frac crew over the second half of 2020.
Northern Delaware•Oklahoma– Our net sales volumes were 960 mboed, including 16 mbbld of oil sales. During the quarter, we suspended all drilling and completions operations in Oklahoma; we do not plan to drill any additional wells in Oklahoma during 2020.
30

•Northern Delaware – Our net sales volumes were 30 mboed, including 16 mbbld of oil sales and we brought 6 gross company-operated wells to sales. We suspended all drilling and completions operations during the third quarter and expect to bring only a limited number of 2017, reflectingwells to sales during the first full quarterremainder of production since the close of our acquisitionsyear.
International
Net sales volumes were lower in the second quarter of 2017. During2020 compared to the thirdsecond quarter of 2017, we brought 5 wells to sales in the Northern Delaware Wolfcamp and Bone Spring formations, while drilling our first multi-well pad.
Other United States – Net sales volumes declined in the third quarter of 20172019 primarily due to thetiming of E.G liftings and disposition of Wyoming and certain non-operated conventional assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for information about dispositions.


International E&P
Net sales volumes were higher in the third quarter of 2017 compared to the third quarter of 2016 primarily due to the resumption of sales volumes and production in Libya and timing of our Brae liftings in the U.K. business. The following table provides details regarding net sales volumes for our significant operations within this segment.segment:
Three Months Ended June 30,Six Months Ended June 30,
Net Sales Volumes20202019Increase (Decrease)20202019Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea84  95  (12)%83  85  (2)%
United Kingdom(a)
—  10  (100)%—  11  (100)%
Other International—  2  (100)%—  2  (100)%
Total International
84  107  (21)%83  98  (15)%
Equity Method Investees
LNG (mtd)
4,635  5,321  (13)%4,850  4,981  (3)%
Methanol (mtd)
738  1,134  (35)%962  1,069  (10)%
Condensate and LPG (boed)
10,896  11,080  (2)%10,767  10,488  3 %
 Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes2017 2016 Increase (Decrease) 2017 2016 Increase
(Decrease)
Equivalent Barrels (mboed)
           
Equatorial Guinea119 115 3% 109 100 9%
United Kingdom(a)
20 11 82% 16 14 14%
Libya23 — 100% 15 — 100%
Other International3 — 100% 2 — 100%
Total International E&P165 126 31% 142 114 25%
Equity Method Investees    
      
LNG (mtd)
6,943 6,620 5% 6,447 5,584 15%
Methanol (mtd)
1,366 1,529 (11)% 1,285 1,371 (6)%
Condensate & LPG (boed)
17,216 16,766 3% 14,467 12,775 13%
(a)Includes natural gas acquired for injection and subsequent resale.
(a)
Includes natural gas acquired for injection and subsequent resale.

•Equatorial Guinea – Net sales volumes in the first nine months of 2017 were higher than the first nine months of 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016 and the timing of liftings.
United Kingdom – Third quarter 2017 net sales volumes were higher compared to the thirdsecond quarter of 2016 due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes.
Libya – Our Libya operations have been interrupted in recent years due to civil unrest. In late 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued without interruption during the third quarter of 2017.



Market Conditions
Crude oil, natural gas and NGL benchmarks increased in the third quarter and first nine months of 2017 as2020 were lower compared to the same period in 2016; as a result, we experienced increased price realizations associated with those benchmarks. Additional detail on market conditions, including2019 due to timing of liftings. We expect our average price realizations and benchmarks for crude oil, NGLsproduction in the third quarter of 2020 to decline sequentially due to the impact of expected higher realized prices, which would reduce our net interest under the production sharing contract, higher third quarter facility downtime, and natural gas relativefield decline.
•United Kingdom – In July 2019, we closed on the sale of our U.K. business. See Note 4 to the consolidated financial statements for further information.
31

Market Conditions
Commodity prices are the most significant factor impacting our revenues, profitability, operating segments, follows.cash flows, the amount of capital we invest in our business, payment of dividends and funding of share repurchases. Commodity prices declined substantially in the first half of 2020 resulting from demand contraction related to the global pandemic and increased supply following the OPEC decision to increase production. A revised OPEC deal to reduce production was agreed early in the second quarter of 2020 and oil prices partially recovered in the latter part of the second quarter. However, given the scale of worldwide demand contraction, we expect commodity prices to remain volatile. Refer to Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K for further discussion on how further declines in commodity prices could impact us. 
United States E&P
        The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the thirdsecond quarter and first ninesix months of 20172020 and 2016.2019.
Three Months Ended June 30,Six Months Ended June 30,
20202019Increase (Decrease)20202019Increase (Decrease)
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)
$21.65  $59.18  (63)%$33.60  $56.72  (41)%
Natural gas liquids (per bbl)
7.09  14.60  (51)%8.54  15.09  (43)%
Natural gas (per mcf)(c)
1.44  1.89  (24)%1.52  2.36  (36)%
Benchmarks
WTI crude oil average of daily prices (per bbl)
$28.00  $59.91  (53)%$36.82  $57.45  (36)%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)
25.66  66.32  (61)%37.60  63.37  (41)%
Mont Belvieu NGLs (per bbl)(d)
12.25  19.20  (36)%12.70  21.19  (40)%
Henry Hub natural gas settlement date average (per mmbtu)
1.72  2.64  (35)%1.83  2.89  (37)%
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 Increase (Decrease) 2017 2016 Increase (Decrease)
Average Price Realizations (a)
           
Crude Oil and Condensate (per bbl) (b)
$46.65 $41.35 13% $46.93 $36.37 29%
Natural Gas Liquids (per bbl)
20.86 12.44 68% 19.32 11.79 64%
Total Liquid Hydrocarbons (per bbl)
40.48 34.00 19% 40.20 30.79 31%
Natural Gas (per mcf) (c)
2.71 2.67 1% 2.91 2.22 31%
Benchmarks           
WTI crude oil (per bbl)
$48.20 $44.94 7% $49.36 $41.53 19%
LLS crude oil (per bbl)
51.61 46.52 11% 51.72 43.19 20%
Mont Belvieu NGLs (per bbl) (d)
23.91 17.04 40% 22.61 16.21 39%
Henry Hub natural gas (per mmbtu)
3.00 2.81 7% 3.17 2.29 38%
(a)Excludes gains or losses on commodity derivative instruments.
(a)
Excludes gains or losses on commodity derivative instruments.
(b)
Inclusion of realized gains on crude oil derivative instruments would have increased liquid hydrocarbons average price realizations by $2.42 per bbl and $1.55 per bbl for the third quarter 2017 and 2016, and $1.35 per bbl and $1.10 per bbl for the first nine months of 2017 and 2016.
(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 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average price realizations by $1.59 per bbl and $0.32 per bbl for the second quarter 2020 and 2019 and $1.53 per bbl and $0.70 per bbl for the first six months of 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.
Crude oil and condensate– Our crude oil and condensate pricePrice realizations may differ from the benchmarkbenchmarks due to the quality and location of the product.
Natural gas liquids– The majority of our NGLsales volumes are sold at reference to Mont Belvieu prices.
Natural gas–A significant portion of our natural gas production in the U.S. isvolumes are sold at bid-week prices, or first-of-month indices relative to our specific producing areas.
International E&P
The following table presents our average price realizations and the related benchmark for crude oil for the thirdsecond quarter and first ninesix months of2017 2020 and 2016.2019.
Three Months Ended June 30,Six Months Ended June 30,
20202019Increase (Decrease)20202019Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)
$13.79  $58.21  (76)%$24.40  $56.36  (57)%
Natural gas liquids (per bbl)
1.00  1.67  (40)%1.00  1.81  (45)%
Natural gas (per mcf)
0.24  0.35  (31)%0.24  0.41  (41)%
Benchmark
Brent (Europe) crude oil (per bbl)(a)
$29.34  $68.92  (57)%$39.89  $66.05  (40)%
(a)Average of monthly prices obtained from the United States Energy Information Agency website.
32

 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 Increase (Decrease) 2017 2016 Increase
(Decrease)
Average Price Realizations           
Crude Oil and Condensate (per bbl)
$51.23 $41.45 24% $49.81 $38.99 28%
Natural Gas Liquids (per bbl)
2.25 1.93 17% 2.63 2.25 17%
Liquid Hydrocarbons (per bbl)
43.69 30.40 44% 40.40 28.96 40%
Natural Gas (per mcf)
0.51 0.46 11% 0.54 0.52 4%
Benchmark    
     
Brent (Europe) crude oil (per bbl) (a)
$52.11 $45.79 14% $51.82 $41.67 24%
(a)
Average of monthly prices obtained from EIA website.

United Kingdom

Crude oil and condensate –Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. business on July 1, 2019.
Our U.K. liquid hydrocarbon
Equatorial Guinea
Crude oil and condensate – Alba field liquids production is primarily condensate and generally sold in relation to the Brent crude benchmark. Our production fromAlba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshoreunder a fixed price long term contract. Alba Plant. The Alba Plant LLC extracts NGLs and secondary condensate which have been supplied under a long-term contract at a fixed price, leaving dry natural gas. The extracted NGLs and secondary condensate areis then sold by Alba Plant LLC at market prices, with our share of its income/lossthe revenue reflected in income from equity method investments andon the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas fromto the Alba Plant is suppliedfield for distribution and sale to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and naturalEG LNG.
Natural gas will not fully track market price movements. Because of the location and limited local demand for naturalliquids –Wet gas in E.G., we consider the prices under the contracts withis sold to Alba Plant LLC EGHoldingsat a fixed-price term contract resulting in realized prices not tracking market price. Alba Plant LLC extracts and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. EGHoldings and AMPCO process the gas into LNG and methanol,keeps NGLs, which are sold at market prices,price, with our share of their income/lossincome from Alba Plant LLC being reflected in the income from equity method investments line item on the Consolidated Statementsconsolidated statements of Income. Although uncommon, any dryincome.
Natural gas not sold is returned offshore and re-injected into–Dry natural gas, processed by Alba Plant LLC on behalf of the Alba field for later production.is sold by the Alba field to EG LNG and AMPCO at fixed-price long term contracts resulting in realized prices not tracking market price. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO. EG LNG sells LNG on a market-based long-term contract and AMPCO markets methanol at market prices.

Results of Operations
Three Months Ended SeptemberJune 30, 20172020 vs. Three Months Ended SeptemberJune 30, 20162019
Sales and other operating revenues, including related party Revenues from contracts with customersare presented by segment in the table below:
 Three Months Ended June 30,
(In millions)20202019
Revenues from contracts with customers
United States$462  $1,200  
International28  181  
Segment revenues from contracts with customers$490  $1,381  
 Three Months Ended September 30,
(In millions)2017 2016
Sales and other operating revenues, including related party   
United States E&P$806
 $604
International E&P364
 152
Segment sales and other operating revenues, including related party$1,170
 $756
Unrealized gain (loss) on commodity derivative instruments(56) 25
Sales and other operating revenues, including related party$1,114
 $781
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.
Increase (Decrease) Related to
(In millions)Three Months Ended June 30, 2019Price RealizationsNet Sales VolumesThree Months Ended June 30, 2020
United States Price/Volume Analysis
Crude oil and condensate$1,021  $(625) $(35) $361  
Natural gas liquids84  (38) (9) 37  
Natural gas79  (17) (8) 54  
Other sales16  10  
Total$1,200  $462  
International Price/Volume Analysis
Crude oil and condensate$161  $(63) $(78) $20  
Natural gas liquids1  —  —  1  
Natural gas13  (4) (2) 7  
Other sales6  —  
Total$181  $28  
33

  Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) September 30, 2016 Price Realizations Net Sales Volumes September 30, 2017
United States E&P Price-Volume Analysis
Liquid hydrocarbons $508
 $110
 $62
 $680
Natural gas 78
 1
 13
 92
Realized gain on commodity        
    derivative instruments 17
 

 

 34
Other sales 1
 

 

 —
Total $604
     $806
International E&P Price-Volume Analysis
Liquid hydrocarbons $125
 $99
 $101
 $325
Natural gas 20
 2
 1
 23
Other sales 7
     16
Total $152
     $364
Marketing revenues decreased $32 million inNet gain (loss) on commodity derivatives In the thirdsecond quarter of 2017 from2020, the comparable 2016 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 basednet loss on market dynamics, it can fluctuate from period to period. The decrease is primarily related to lower marketed volumes in the United States due to non-core asset dispositions.
Net gain on disposal of assets decreased$28commodity derivatives was $70 million, in the third quarter of 2017 primarily relatedcompared to the same period in 2019, which was a net gain on sale of certain non-operated assets primarily in West Texas$16 million. We have multiple crude oil and New Mexico innatural gas derivative contracts that settle against various indices. We record commodity derivative gains/losses as the third quarter of 2016.index pricing and forward curves change each period. See Note 615 to the consolidated financial statements for further information.

Income from equity method investmentsdecreased $183 million for the second quarter of 2020 from the comparable 2019 period primarily due to an impairment of $152 million to an investment in an equity method investee, and lower volumes and price realizations associated with our investees. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.

Production expenses increased $34 decreased $64 million in the thirdsecond quarter of 20172020 versus the same period in 2016 due to higher sales volumes. United States E&P increased $8 million2019, primarily due to new wells to sales across allas a result of lower well workover and maintenance activities, lower U.S. resource plays, as well as our acquisitioncontract labor, and development of Northern Delaware. This was partially offset by the dispositionsale of our non-core assets in WyomingU.K. business which closed during the second half of 2016. International E&P increased $26 million primarily due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes in the third quarter of 2017.2019.
The thirdsecond quarter of 20172020 production expense rate (expense per boe) for United States E&P was lower due to sales volumes increasing atfor International as a higher rate thanresult of the sale of our U.K. business which closed during the third quarter of 2019. Our U.S. production costs. The expense rate was lower as a result of the same reasons identified in the preceding paragraph in the second quarter of 2020. While the production expense rates for each of our U.S. and International E&P increased duesegments were significantly lower than the prior period, we still expect our full year production expense rates to an increase in sales volumes in U.K.be consistent with previously provided guidance of $4.25 - $5.25 per boe and Libya.$2.15 - $2.65 per boe, respectively.
The following table provides production expense and production expense rates for each segment:
 Three Months Ended September 30,
($ per boe)2017 2016
Production Expense Rate   
United States E&P
$5.38
 
$5.70
International E&P
$4.82
 
$4.05
Three Months Ended June 30,
($ per boe)20202019Increase (Decrease)20202019Increase (Decrease)
Production Expense and RateExpenseRate
United States$114  $147  (22)%$4.09  $4.89  (16)%
International$15  $46  (67)%$1.88  $4.72  (60)%
Marketing costsShipping, handling and other operating decreased $31$65 million in the thirdsecond quarter of 2017 from the comparable 2016 period, consistent with the marketing revenues changes discussed above.
Other operating expenses decreased $74 million in the third quarter of 20172020 primarily due to lower NGL shipping and handling rates realized in Bakken along with lower net sales volumes in Oklahoma. To the termination payment ofextent that our Gulf of Mexico deepwater drilling rig infuture Bakken realized NGL prices exceed those as compared to the thirdsecond quarter, of 2016.we expect our shipping and handling costs to increase as well.
Exploration expensesinclude unproved property impairments, dry well costs, geological and geophysical, and other costs, whichincreased $211 millionremained flat in comparison to the thirdsecond quarter of 2017.Exploration expenses in certain non-core properties in our International E&P segment increased $159 million primarily as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to exploration expenses of $43 million during the third quarter of 2017. See Note 13 to the consolidated financial statements for further information.2019.
The following table summarizes the components of exploration expenses:
 Three Months Ended June 30,
(In millions)20202019Increase (Decrease)
Exploration Expenses
Unproved property impairments$17  $20  (15)%
Dry well costs1  —  — %
Geological and geophysical3  3  — %
Other5  3  67 %
Total exploration expenses$26  $26  — %
 Three Months Ended September 30,
(In millions)2017 2016
Exploration Expenses   
Unproved property impairments$172
 $28
Dry well costs77
 9
Geological and geophysical2
 1
Other43
 45
Total exploration expenses$294
 $83
Depreciation, depletion and amortizationincreased $119decreased $8 million in the second quarter of 2020 primarily due to the sale of our U.K. business which closed during the third quarter of 2017 primarily as a result of an increase of $88 million in the United States E&P due to higher sales volumes across all U.S. resource plays, as well as our acquisition and development of Northern Delaware. In our International E&P segment, we had an increase of $36 million primarily due to timing of our Brae liftings which resulted in an increase in our U.K. sales volumes, increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016, and the resumption of sales volumes and production in Libya.2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense.


The DD&A rate (expense per boe), which is impacted by field-level changes in reserves, capitalized costs and sales volume mix by field,volumes, can also cause changes toimpact our DD&A.&A expense. Our United States E&PInternational DD&A rate increased indecreased primarily due to the sale of our U.K. business which closed during the third quarter of 2017 primarily due to our acquisition and development in Northern Delaware and a reduction to Eagle Ford proved developed reserve base in the fourth quarter of 2016. The DD&A rate for International E&P increased primarily due to sales volume mix changes between countries in the current quarter. 2019.

34

The following table provides DD&A expense and DD&A expense rates for each segment.segment:
Three Months Ended June 30,
($ per boe)20202019Increase (Decrease)20202019Increase (Decrease)
DD&A Expense and RateExpenseRate
United States$569  $561  1 %$20.28  $18.72  8 %
International$22  $38  (42)%$2.86  $3.92  (27)%
 Three Months Ended September 30,
($ per boe)2017 2016
DD&A Rate   
United States E&P
$23.64
 
$22.37
International E&P
$6.68
 
$5.72
Impairments increased $154decreased $18 million in the third quarter of 2017 from the comparable 2016 period. This increase was primarily consisting of $136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of our anticipated sales and lower forecasted long-term commodity prices Additionally, included in proved property impairments was $65 million relating to certain non-core proved properties in the Gulf of Mexico as a result of lower forecasted long-term commodity pricesour United States segment in the thirdsecond quarter of 2017.2019. See Note 11 to the consolidated financial statements for more detail.
Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $9decreased $49 million in the third quarter of 2017 versus the same period in 2016. The increase in the third quarter of 2017 is primarily due to an increase inlower price realizations and lower sales volumes in the thirdU.S. segment in the second quarter of 2017. The following table summarizes the components2020.
Provision (benefit) for income taxesreflects an effective income tax rate of taxes other than income:
 Three Months Ended September 30,
(In millions)2017 2016
Taxes other than income   
Production and severance$32
 $23
Ad valorem3
 3
Other9
 9
Total taxes other than income$44
 $35
Net interest and otherdecreased $54 million2% in the thirdsecond quarter of 2017 versus2020, as compared to an effective income tax rate of 17% in the same period in 2016. This decrease was primarily due to the terminationsecond quarter of our forward starting interest rate swaps, which resulted in a gain of $47 million.2019. See Note 15 7to the consolidated financial statements for further detail.
Loss on early extinguishment of debtrecognized $46 million in the third quarter of 2017 primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes. See Note 17 to the consolidated financial statements for further detail.
Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 31% in the third quarter of 2017, as compared to a benefit of 34% in the third quarter of 2016. We placed a full valuation allowance on our net federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any net federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for more detaildetailed discussion concerning the rate changes.
Discontinued operations are presented net of tax. See Note 6 to the consolidated financial statements for financial information concerning our discontinued operations.


Segment Income (Loss)
Segment income (loss) represents income (loss) from operations excludingwhich excludes certain items not allocated to our operating segments, net of income taxes, attributable to the operating segments.taxes. A portion of our corporate and operations support general and administrative support costs are not allocated to the operating segments. GainsThese 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 impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension settlement losses,settlements and curtailments, or other items that affect comparability also(as determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
Three Months Ended September 30, Three Months Ended June 30,
(In millions)2017 2016(In millions)20202019Increase (Decrease)
United States E&P$(38) $(59)
International E&P104
 59
United StatesUnited States$(365) $215  (270)%
InternationalInternational(6) 96  (106)%
Segment income (loss)66
 —
Segment income (loss)(371) 311  (219)%
Items not allocated to segments, net of income taxes(665) (206)Items not allocated to segments, net of income taxes(379) (150) (153)%
Income (loss) from continuing operations(599) (206)
Income (loss) from discontinued operations (a)
—
 14
Net income (loss)$(599) $(192)Net income (loss)$(750) $161  (566)%
(a) We entered into an agreementUnited States segment loss In the second quarter of 2020, U.S. segment loss was$365 million after-tax versus $215 million income after-tax for the same period in 2019, primarily due to sell our Canadian businesslower price realizations and sales volumes in the firstcurrent quarter, which was partially offset by lower production taxes, shipping and handling expense, and production expense.
International segment loss In the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
 United States E&P2020, International segment loss decreased $21 was$6 million after-tax versus $96 million income after-tax for the same period in 2019, primarily due to lower price realizations in E.G. resulting in lower income from equity method investments and the sale of our U.K. business in the third quarter of 2017 primarily due to higher price realizations and higher sales volumes, which resulted in an increase in production expenses, DD&A and taxes other than income which partially offset the increase to revenues. This was partially offset by a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period.2019.
International E&P segment incomeincreased $45 million after-tax in the third quarter of 2017 primarily due to higher price realizations and an increase in sales volumes in U.K. and Libya. This resulted in an increase in production expense, DD&A and income tax provision which partially offset the increase to revenues.
35


Results of Operations
NineSix Months Ended SeptemberJune 30, 20172020 vs. NineSix Months Ended SeptemberJune 30, 20162019
Consolidated Results of Operation
Sales and other operating revenues, including related party Revenues from contracts with customers are presented by segment in the table below:
 Nine Months Ended September 30,
(In millions)2017 2016
Sales and other operating revenues, including related party   
United States E&P$2,175
 $1,714
International E&P787
 407
Segment sales and other operating revenues, including related party$2,962
 $2,121
Unrealized gain (loss) on commodity derivative instruments64
 (89)
Sales and other operating revenues, including related party$3,026
 $2,032
 Six Months Ended June 30,
(In millions)20202019
Revenues from contracts with customers
United States$1,432  $2,262  
International82  319  
Segment revenues from contracts with customers$1,514  $2,581  


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.

Increase (Decrease) Related to
(In millions)Six Months Ended June 30, 2019Price RealizationsNet Sales VolumesSix Months Ended June 30, 2020
United States Price/Volume Analysis
Crude oil and condensate$1,880  $(818) $127  $1,189  
Natural gas liquids161  (68) (5) 88  
Natural gas182  (66) 5  121  
Other sales39  34  
Total$2,262  $1,432  
International Price/Volume Analysis
Crude oil and condensate$274  $(84) $(125) $65  
Natural gas liquids3  (1) —  2  
Natural gas28  (11) (2) 15  
Other sales14  —  
Total$319  $82  
  Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2016 Price Realizations Net Sales Volumes September 30, 2017
United States E&P Price-Volume Analysis (a)
Liquid hydrocarbons $1,468
 $434
 $(50) $1,852
Natural gas 191
 64
 14
 269
Realized gain on commodity        
    derivative instruments 41
 

   51
Other sales 14
     3
Total $1,714
     $2,175
International E&P Price-Volume Analysis
Liquid hydrocarbons $319
 $193
 $172
 $684
Natural gas 63
 3
 5
 71
Other sales 25
     32
Total $407
     $787
(a) Nine        Net gain (loss) on commodity derivatives In the first six months ending September 30, 2017 includesof 2020, the net gain on commodity derivatives was $132 million, compared to the same period in 2019 which was a net sales volume reduction from September 30, 2016loss of 17 mboed primarily consisting of$75 million. We have multiple crude oil and natural gas derivative contracts that settle against various indices. We record commodity derivative gains/losses as the disposition of Wyomingindex pricing and certain non-operated assets in West Texas and New Mexico in 2016.forward curves change each period. SeeNote 615 to the consolidated financial statements for further information.
Marketing revenues for the first nine months of 2017 decreased by $85 million, primarily related to lower marketed volumes in the United States E&P segment due to non-core asset dispositions. 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.
Income from equity method investmentsincreased $73decreased $206 million for the first ninesix months of 20172020 primarily due to higheran impairment of $152 million to an investment in an equity method investee in the second quarter of 2020 as well as lower price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement inlower net sales volumes primarily driven by the completion of the Alba field compression projectfrom equity method investments in E.G. duringdue to the second halfplanned triennial turnaround in the first quarter of 2016.2020.
Net gain on disposal of assetsdecreased $255$27 million for the first ninesix months of 2017. This decrease was2020 primarily related toas a result of the sale of non-core assetsour working interest in the Droshky field (Gulf of Mexico), which closed during the first quarter of 2019.
Other incomedecreased $35 million in the first halfsix months of 20162020 primarily due to income recognized in Wyoming, West Texas and New Mexico, and the Gulf of Mexico. See Note 62019 arising from indemnification payments received from Marathon Petroleum Corporation (“MPC”). Pursuant to the consolidated financial statementsTax Sharing Agreement we entered into with MPC, in connection with the 2011 spin-off transaction, MPC agreed to indemnify us for information about dispositions.certain liabilities. The indemnity relates to tax and interest allocable to MPC as a result of the closure of the IRS Audit in the first quarter of 2019.
Production expenses for the first ninesix months of 20172020 decreased by $11$91 million compared to the same period in 2016.2019. Production expense in our International segment decreased $64 million primarily as a result of the sale of our U.K. business, which closed during the third quarter of 2019. Production expense in our United States E&P declined $28segment decreased $29 million primarily due to the disposition of our non-core assets in Wyoming during the second half of 2016 which was partially offset by our acquisitionslower well workover and development in the Oklahoma STACKmaintenance activities, and Northern Delaware. International E&P increased $17 million primarily due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes in the first nine months of 2017.lower contract labor.
The first ninesix months of 20172020 production expense rate (expense per boe) was lower for our United States E&P was lowersegment due to the disposition of non-core assets in Wyoming as volumes remained flat. Theaforementioned reasons. Expense per boe for our International E&P expense ratesegment decreased in the first nine months of 2017 primarily due to an increase in sales volumes in E.G.sale of the U.K. business, which closed during the third quarter of 2019.
36

The following table provides production expense and Libya, combined with lower planned maintenance costs in E.G. due to planned maintenance in the first half of 2016.production expense rates for each segment:
Six Months Ended June 30,
($ per boe)20202019Increase (Decrease)20202019Increase (Decrease)
Production Expense and RateExpenseRate
United States$257  $286  (10)%$4.37  $5.04  (13)%
International$32  $96  (67)%$2.11  $5.40  (61)%
 Nine Months Ended September 30,
($ per boe)2017 2016
Production Expense Rate   
United States E&P
$5.66
 
$6.06
International E&P
$4.45
 
$4.98
Marketing costsShipping, handling and other operating expensesdecreased $80$75 million in the first ninesix months of 20172020 from the comparable 20162019 period, consistent with the marketing revenues changes discussed above.primarily as a result of lower NGL shipping and handling rates realized in Bakken as well as lower net sales volumes in Oklahoma.
Exploration expensesinclude unproved property impairments, dry well costs, geological and geophysical, and other, which increased $63decreased $31 million in the first ninesix months of 2017 versus the comparable 2016 period. Exploration expenses2020. Decreases in


certain non-core properties in our International E&P segment increased $159 million unproved property impairments were primarily as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally,driven by our decision not to develop the Tchicuate offshore Blockdrill certain leases related to resource exploration in the Republic of Gabon resulted in an increase to exploration expenses of $43 million during the thirdfirst quarter of 2017. See Note 13 to the consolidated financial statements for further information.2019.
The following table summarizes the components of exploration expenses:
 Six Months Ended June 30,
(In millions)20202019Increase (Decrease)
Exploration Expenses
Unproved property impairments$39  $64  (39)%
Dry well costs1  5  (80)%
Geological and geophysical4  9  (56)%
Other10  7  43 %
Total exploration expenses$54  $85  (36)%
 Nine Months Ended September 30,
(In millions)2017 2016
Exploration Expenses   
Unproved property impairments$217
 $172
Dry well costs77
 24
Geological and geophysical3
 1
Other55
 92
Total exploration expenses$352
 $289
Depreciation, depletion and amortization increased $206$82 million in the first ninesix months of 20172020 from the comparable 20162019 period, primarily as a result of an increase of $135 million in the United States E&P due to the acquisitions and development in the Oklahoma STACK and Northern Delaware and our Gunflint field beginning production in the second half of 2016. Also contributing to this higher expense was an increase of $82 millionnet sales volumes in our International E&PU.S. segment resulting fromdriven by first quarter 2020 activity, partially offset by the completion and start-upsale of our Alba field compression project in mid-2016,U.K. business, which closed during the resumptionthird quarter of sales volumes and production in Libya and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016.2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in reserves, capitalized costs and sales volumes, reserves and capitalized costs, can also cause changes toimpact our DD&A. The DD&A rate for United States E&P increased primarily due to the increased rate in the Gulf of Mexico as a result of the Gunflint field achieving first production in mid-2016 and our Oklahoma STACK acquisition. Also contributing to the increase was a reduction to the Eagle Ford proved developed reserve base in the fourth quarter of 2016.expense. The DD&A rate for International E&P increaseddecreased primarily due to sales volume mix changes between countries in the current quarter, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. as a result of dispositions.
The following table provides DD&A expense and DD&A expense rates for each segment.
segment:
 Nine Months Ended September 30,
($ per boe)2017 2016
DD&A Rate 
  
United States E&P
$24.38
 
$21.98
International E&P
$6.83
 
$5.89
Six Months Ended June 30,
($ per boe)20202019Increase (Decrease)20202019Increase (Decrease)
DD&A Expense and RateExpenseRate
United States$1,186  $1,075  10 %$20.15  $18.98  6 %
International$43  $72  (40)%$2.86  $4.06  (30)%


Impairmentsincreased $157$73 million in the first ninesix months of 2017 from the comparable 2016 period. This increase was2020, primarily consisting of $136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of impairment to goodwill for $95 million related to our anticipated sales and lower forecasted long-term commodity prices. Additionally, included in proved property impairments was $65 million relating to certain propertiesInternational reporting unit in the Gulf of Mexico as a result of lower forecasted long-term commodity prices in the thirdfirst quarter of 2017.2020. See Note 11 for discussion of the impairments in further detail.
Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $15decreased $55 million primarily due to lower price realizations in the U.S. segment in the first six months of 2020.
General and administrative decreased$17 million in the first ninesix months of 2017 from2020 primarily as a result of the comparable 2016 period. The increasechange in value of stock-based performance units tied to our total shareholder return (“TSR”) as compared to our peer group and a decrease in other compensation costs.
37

Provision (benefit) for income taxes reflects an effective income tax rate of 2% in the first ninesix months of 2017 is primarily due to a reserve for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:
 Nine Months Ended September 30,
(In millions)2017 2016
Taxes other than income   
Production and severance$79
 $68
Ad valorem8
 22
Other41
 23
Total taxes other than income$128
 $113
General and administrative expensesdecreased $87 million in the first nine months of 20172020, as compared to the same period in 2016. This decrease was primarily due to pension settlement charges, which were reduced in the first nine monthsan effective income tax rate of 2017 to $25 million compared to $93 million(52)% for the same period in 2016.
Net interest and otherdecreased $57 million in the first nine months of 2017 versus the same period in 2016. This decrease was primarily due to the termination of our forward starting interest rate swaps, which resulted in a gain of $47 million.comparable 2019 period. See Note 157 to the consolidated financial statements for further detail.
Loss on early extinguishment of debtrecognized $46 million ina more detailed discussion concerning the first nine months of 2017 primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes. See Note 17 tocomponents impacting the consolidated financial statements for further detail.
Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 37% in the first nine months of 2017, as compared to a benefit of 37% from the comparable 2016 period. We placed a full valuation allowance on our net federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any net federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations are presented net of tax. See the preceding Operations section and Note 6 to the consolidated financial statements for financial information concerning our discontinued operations.


change.
Segment Income (Loss)
Segment income (loss) represents income (loss) from operations excludingwhich excludes certain items not allocated to our operating segments, net of income taxes, attributable to the operating segments.taxes. A portion of our corporate and operations support general and administrative support costs are not allocated to the operating segments. GainsThese 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 impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension settlement losses,settlements and curtailments, or other items that affect comparability also(as determined by the CODM) are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
 Six Months Ended June 30,
(In millions)20202019Increase (Decrease)
United States$(385) $347  (211)%
International(7) 157  (104)%
Segment income (loss)(392) 504  (178)%
Items not allocated to segments, net of income taxes(404) (169) (139)%
Net income (loss)$(796) $335  (338)%
 Nine Months Ended September 30,
(In millions)2017 2016
United States E&P$(224) $(324)
International E&P256
 118
Segment income (loss)32
 (206)
Items not allocated to segments, net of income taxes(834) (498)
Income (loss) from continuing operations(802) (704)
Income (loss) from discontinued operations (a)
(4,893) (65)
Net income (loss)$(5,695) $(769)
(a) We entered into an agreement to sell our Canadian business inUnited States segment loss For the first quartersix months of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
 United States E&P2020, U.S. segment loss decreased $100 was $385 million after-tax versus $347 million income after-tax for the same period in the first nine months2019, primarily as a result of 2017 from the comparable 2016 period primarily due to higherlower crude price realizations and higher DD&A due to higher net sales volumes, which resulted in an increase in DD&A partially offsetting the increase to revenues. This was partially offset by a decrease inlower production taxes, shipping and handling expense, and production expense.
International segment loss For the income tax benefit, which resulted from U.S. valuation allowances in the current period.
first six months of 2020, International E&P segment incomeincreased $138loss was $7 million after-tax versus $157 million income after-tax for the same period in the first nine months of 2017 from the comparable 2016 period 2019,primarily due to higherlower price realizations an increase inand sales volumes in E.G. and Libya and an increase in income from equity investments. This was partially offset by an increaselower costs due to sale of our U.K. business in production expense, DD&A and income tax expense as a resultthird quarter of the increase to sales volumes.2019.

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, 2016,2019, except as discussed below.
Asset Retirement ObligationsImpairment of Equity Method Investments
EstimatesIn the second quarter of retirement costs2020, we recorded an impairment of $152 million to an investment in an equity method investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. Equity method investments are developedassessed for each propertyimpairment whenever changes 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.
Fair value calculated for the purpose of testing our equity method investees for impairment is estimated using the present value of expected future cash flows method. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions and the performance of entities that we do not control. Significant assumptions include:
•Future condensate, NGL, LNG, natural gas & methanol prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, and governmental policies. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in
38

commodity prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors in our Form 10-K for the scopeyear ended December 31, 2019 for further discussion on commodity prices.
•Estimated quantities of feedstock condensate, NGLs and natural gas processed by our investees. There are two primary sets of inputs used to estimate feedstock volumes processed by our investees. The first input involves hydrocarbons produced from our Alba Field. Our equity method investees currently process hydrocarbons from our Alba Field, which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from our Alba Field are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2019 for further discussion on reserves.

The second input involves our estimate of future third-party gas to be processed by our investees. Our investees have capacity to process hydrocarbons from sources other than our Alba field. During 2019, we executed agreements for processing natural gas produced from the third party-owned Alen field through the existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production facility beginning in 2021. Estimated natural gas volumes processed from the Alen field were based on forecasts received from the operator of the dismantlement,Alen field.

•Expected timing of settlement, interpretationproduction. Production forecasts are the outcome of legal, regulatory and contractual requirements, typeengineering studies which estimate reserves, as well as expected capital programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production from the Alba Field that we use in our fair value estimates is consistent with that used in our planning and processing structures, depthcapital investment reviews. The expected timing of water (if applicable), reservoir characteristics, depthproduction from the Alen Field is consistent with forecasts received from the operator of that field.
•Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows
We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. This includes the estimated dividends and/or return of capital we expect to be paid by our equity method investees, which are directly affected by the significant assumptions described in the preceding paragraphs. An estimate of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Currency exchange rates, inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. During the third quarter of 2017 we made revisions to these estimates and reduced the recognized liability by $110 million. This downward revision was primarily duesensitivity to changes in U.K. estimatedassumptions in our cash flow calculations is not practicable, given the numerous other assumptions (e.g. reserves, commodity prices, operating costs, as well as timinginflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of abandonment activitiesthe above listed assumptions would likely be offset by favorable adjustments in the U.K. other assumptions.
SeeNote 1211 to the consolidated financial statements for further information.information regarding the impairment recognized during the second quarter of 2020.
Fair Value Estimates -– Goodwill
Goodwill must be tested        In the first quarter of 2020, a triggering event (significant decline in market capitalization caused by worldwide declines in hydrocarbon demand and corresponding prices) required us to assess our goodwill in the International reporting unit 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, and as of September 30, 2017, we have $115 million of goodwill associated with our International E&P reporting unit.March 31, 2020. We performed our annual impairment test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment,estimated the fair value of our International E&P reporting unit exceeded its book value by over 40%.using a combination of market and income approaches and concluded that a full impairment of $95 million was required. See Note 14 to the consolidated financial statements for further information.

Estimated Quantity of Net Reserves 

Fair Value Estimates - Impairment Assessments of Long-Lived Assets
The continued lowContinued lower commodity price environment resulted inprices could have a downward revisionmaterial effect on the quantity and present value of our long-termproved reserves. To the extent that commodity price assumptions which triggered an assessment of certainprices decline further throughout 2020, 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. Future reserve revisions could also result from changes to our Capital Budget and drilling plans among other things. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to unproved reserves could return to proved reserves as commodity prices improve. Any reduction in proved reserves, especially as a result of continued lower commodity prices, could result in an acceleration of future DD&A expense and impairments to long-lived assets related to oil and gas producing properties for impairment. We estimated the fair values using an income approach and recognized impairments of $65 million during the third quarter of 2017 in the Gulf of Mexico of our United States E&P segment. Additionally, due to the anticipated sale of certain of our non-core long-lived assets in our International E&P segment and the downward revision of our long-term commodity price assumptions, we assessed certain non-core international long-lived assets for impairment. The fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe, resulting in impairments of $136 million during the third quarter of 2017. See Note 14 to the consolidated financial statements for further information.assets.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
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Cash Flows
        Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, payment of dividends, and funding of share repurchases. While we generated cash flows from operations during the first six months of 2020, the lower price environment reduced our cash flow generation compared to the prior year. Should lower prices continue, our ability to generate cash from operations could be negatively affected. The following table presents sources and uses of cash and cash equivalents:
Nine Months Ended September 30,Six Months Ended June 30,
(In millions)2017 2016(In millions)20202019
Sources of cash and cash equivalents 
  
Sources of cash and cash equivalents  
Operating activities - continuing operations$1,487
 $526
Disposals of assets1,757
 837
Borrowings988
 —
Common stock issuance—
 1,236
Operating activitiesOperating activities$710  $1,312  
Disposal of assets, net of cash transferred to the buyerDisposal of assets, net of cash transferred to the buyer9  69  
Other49
 49
Other11  50  
Total sources of cash and cash equivalents$4,281
 $2,648
Total sources of cash and cash equivalents$730  $1,431  
Uses of cash and cash equivalents   Uses of cash and cash equivalents
Cash additions to property, plant and equipment$(1,305) $(949)
Acquisitions, net of cash acquired(1,828) (902)
Debt repayments(1,764) (1)
Debt extinguishment costs(46) —
Additions to property, plant and equipmentAdditions to property, plant and equipment$(946) $(1,262) 
Additions to other assetsAdditions to other assets12  42  
Purchases of common stockPurchases of common stock(92) (266) 
Dividends paid(128) (119)Dividends paid(40) (82) 
Purchases of common stock(10) (5)
Other(26) —
Other—  (29) 
Total uses of cash and cash equivalents$(5,107) $(1,976)Total uses of cash and cash equivalents$(1,066) $(1,597) 
Cash flows generated from operating activities in the first ninesix months of 2017 was higher2020 were 46% lower primarily as commodity prices improved compared to the first nine months of 2016. This drove an increase in price realizations in the first nine months of 2017. Consolidated average liquid hydrocarbon price realizations increased by more than 30% during the first nine months of 2017 as compared to the prior period. This increase in price realization coupled with our increased sales volumes and continued focus on cost reduction resulted in our increased cash flows generated from operating activities.
Proceeds from the disposals of assets for the first nine months of 2017 are from the disposal of our Canadian business; see Note 6 to the consolidated financial statements for further information concerning dispositions. Borrowings during the first nine months of 2017 are a result of the issuance of $1 billion of 4.4% senior unsecured notes due in 2027; see Note 17 to the consolidated financial statements for further detail. Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock; see Note 19 to the consolidated financial statements for additional information.lower commodity price realizations.


Additions to property, plant and equipment in the first nine months of 2017 were consistent with our Capital Program. The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
Nine Months Ended September 30,Six Months Ended June 30,
(In millions)2017 2016(In millions)20202019
United States E&P$1,465
 $684
International E&P27
 62
United StatesUnited States$698  $1,292  
InternationalInternational—  15  
Corporate20
 11
Corporate9  8  
Total capital expenditures1,512
 757
Total capital expenditures707  1,315  
Decrease (increase) in capital expenditure accrual(207) 192
Change in capital expenditure accrualChange in capital expenditure accrual239  (53) 
Total use of cash and cash equivalents for property, plant and equipment$1,305
 $949
Total use of cash and cash equivalents for property, plant and equipment$946  $1,262  
The decline in our capital expenditures for the U.S. segment was caused by lower drilling and completions activities across all four of our shale basins.
In the secondfirst quarter of 2017,2020, we closed on our acquisitionacquired approximately 9 million common shares at a cost of the Northern Delaware assets for a purchase price of $1.8 billion, subject to closing adjustments.$85 million, which were held as treasury stock. See Note 518 to the consolidated financial statements for additionalfurther information.
During the third quarter of 2017, we used the net proceeds of the borrowing disclosed above plus existing cash on hand to redeem $1.76 billion in senior unsecured notes resulting in a recognized loss on early extinguishment of debt of $46 million, primarily due to make-whole call provisions.
The Board of Directors approved a $0.05 per share dividend for the second quarter of 2017, which was paid in the third quarter of 2017. See Capital Requirements below for additional information about the third quarter dividend.
Liquidity and Capital Resources
In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020, to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving credit facility.Credit Facility. At SeptemberJune 30, 2017,2020, we had approximately $5.2$3.5 billion of liquidity consisting of $1.8$0.5 billion in cash and cash equivalents and $3.4$3.0 billion available under our revolving credit facility. Credit Facility. Additionally, in early July, we collected an $89 million cash refund related to alternative minimum tax credits and associated interest. We expect cash flow from operations to improve during each of the third and fourth quarters of 2020, relative to the second quarter 2020, commensurate with an expected increase in commodity prices relative to the second quarter. See Item 1A. Risk Factors for a more detailed discussion of recent developments affecting the energy industry.
40

Our working capital requirements are supported by these sourcesour cash and wecash equivalents and our Credit Facility. We may draw on our revolving credit facilityCredit 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 program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are 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.
General economic conditions, commodity prices, and financial, business and other factors, including the global pandemic, could affect our operations and our ability to access the capital markets. Our corporate
During the first half of 2020, commodity prices significantly declined due to the combined impacts of global crude oil oversupply and lower demand for hydrocarbons due to the global pandemic. As a result, credit ratings remained unchanged duringrating agencies reviewed many companies in the third quarter and as of September 30, 2017 are: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (negative); and Moody's Investor Services, Inc. Ba1 (stable).industry, including us. We continue to be rated investment grade at all three primary credit rating agencies. A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and could result in additional collateralcredit support requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 20162019 for a discussion of how a further downgrade in our credit ratings could affect us.


On May 6, 2020, our Board of Directors temporarily suspended our quarterly dividend payment as we prioritize our liquidity and balance sheet.
Capital Resources
Credit Arrangements and Borrowings
At SeptemberJune 30, 2017,2020, we had no borrowings against our revolving credit facility.
Credit Facility. At SeptemberJune 30, 2017,2020, we had $6.5$5.5 billion in long-termof total debt outstanding, with our next significant debt maturity in the amount of $600 million$1.0 billion due in 2020.November 2022. 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.
We continue to own $400 million of St. John the Baptist, State of Louisiana revenue refunding bonds that were originally issued in December 2017. In July, we announced that we had delivered to the trustee and remarketing agent a conditional notice of conversion of up to $400 million of the bonds to remarket them in August. Information about these bonds are available on the website of the Municipal Securities Rulemaking Board via its Electronic Municipal Market Access system at www.msrb.org. Information on that website is not incorporated by reference into this filing.
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The new Houston office location is expected to be completed in 2021. The lessor and other participants are providing financing for up to $380 million, to fund the estimated project costs. As of June 30, 2020, project costs incurred totaled approximately $87 million, including land acquisition and construction costs. In June 2020, we submitted a notice to the lessor, as the construction agent, to reduce the financing capacity to $340 million to align with our revised estimate of the project costs. We expect the reduction to become effective in August 2020.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known“well-known seasoned issuer"issuer” for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. 
Asset DisposalDebt-To-Capital Ratio
In the second quarter of 2017, we closed on the sale ofThe Credit Facility includes a covenant requiring that our Canadian business for $2.5 billion, excluding closing adjustments. Under the termstotal debt to total capitalization ratio not exceed 65% as of the agreement, $1.8 billionlast day of the fiscal quarter. Our ratio was paid to us upon closing33% and the remaining proceeds of $750 million will be paid to us in31% at June 30, 2020 and at December 31, 2019, respectively.
Capital Requirements
Share Repurchase Program
In the first quarter of 2018.2020, we acquired approximately 9 million common shares at a cost of $85 million under our share repurchase program. While the share repurchase program has $1.3 billion of remaining authorization, we elected to suspend additional share repurchases to preserve liquidity.
In the third quarter of 2017, we entered into agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments.
Cash-Adjusted Debt-To-Capital Ratio
Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash and cash equivalents) was 28% at September 30, 2017, compared to 21% at December 31, 2016.
 September 30, December 31,
(In millions)2017 2016
Long-term debt due within one year$—
 $686
Long-term debt6,488
 6,581
Total debt$6,488
 $7,267
Cash and cash equivalents$1,795
 $2,488
Equity$11,775
 $17,541
Calculation: 
  
Total debt$6,488
 $7,267
Minus cash and cash equivalents1,795
 2,488
Total debt minus cash, cash equivalents$4,693
 $4,779
Total debt$6,488
 $7,267
Plus equity11,775
 17,541
Minus cash and cash equivalents1,795
 2,488
Total debt plus equity minus cash, cash equivalents$16,468
 $22,320
Cash-adjusted debt-to-capital ratio28% 21%
Capital Requirements
On October 25, 2017, our Board of Directors approved a dividend of $0.05 per share for the third quarter of 2017 payable December 11, 2017 to stockholders of record at the close of business on November 15, 2017.
As of September 30, 2017, we plan to make contributions of up to $8 million to our funded pension plans during the remainder of 2017.
Contractual Cash Obligations
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As of SeptemberJune 30, 2017, there are no material changes to2020, our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2016 Annual Report on Form 10-K, except for cash obligations primarily relating to the sale of our Canadian business and the issuance of $1 billion of 4.4% senior unsecured notes due in 2027 and redemption of approximately $1.8 billion of debt due in 2017, 2018 and 2019. See Note 6 and Note 17 to the consolidated financial statements for additional information. As a result, as of September 30, 2017, our consolidated contractual cash obligations fromas it relates to our continuing operations hastransportation and processing commitments decreased by $1,392approximately $79 million from December 31, 2016. Our short($8 million in 2021, $11 million in 2022, $11 million in 2023, $11 million in 2024 and long term debt (including$38 million thereafter) related to the cancellation of a transportation service agreement in the Bakken resource play.  




interest) decreased $633 million, purchase obligations under oil and gas activities decreased by $54 million, and service and materials contracts decreased $642 million when comparing September 30, 2017 to December 31, 2016.
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Environmental Matters and Other Contingencies
In July 2015,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 receivedreceive 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 requestnumber of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for information fromcontrol of pollutants released into the EPAenvironment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
There have been no significant changes to the environmental, health and safety matters under Section 114 of the Clean Air Act regarding several tank batteries usedItem 1. Business or Item 3. Legal Proceedings in our Bakken operations.  We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000, which was reduced to $130,500 under the terms of the settlement agreement by mitigating corrective actions.  We paid the penalty in September 2017 and do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect2019 Annual Report on our financial position, results of operation or cash flows. 
Form 10-K. See Note 2124 to the consolidated financial statements for a description of other contingencies.
Forward-Looking Statements
This reportQuarterly Report on Form 10-Q 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, including without limitation statements regarding our future performance, business strategy, reserve estimates, asset quality, production guidance,operational and financial strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2020 Capital Budget and the planned allocation thereof; planned capital plans, costexpenditures and expense estimates, asset acquisitionsthe impact thereof; expectations regarding future economic and dispositions, futuremarket conditions and their effects on us; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and future payments for our Canadian dispositionproduction and other planssales expectations, and objectives for future operations,the drivers thereof, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend,"” “may,” “outlook,” “plan,” “project,” “seek,” “should,” “target,” “will,” “would” or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While we believe our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, but not limited to:
•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 jurisdictions in which we operate,U.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation rates,rates;
•actions taken by the members of OPEC and Russia affecting the production and pricing of crude oil; and other global and domestic market conditions;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 Canadian disposition;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;obligations, including due to bankruptcy;
unforeseen •hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks;•shortages of key personnel, including employees, contractors and subcontractors;
43

•cyber-attacks;
•changes in safety, health, environmental, tax and other regulations;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 20162019 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 undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

44


Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion        We are exposed to market risks in the normal course of ourbusiness including commodity price risk managementand interest rate risk. We employ various strategies, including the use of financial derivatives to manage the risks related to commodity price fluctuations. See Note 15and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2016 Annual Report on Form 10-K. Notes 14 and 15Note 16 to the consolidated financial statements include additional disclosures regardingfor detail relating to our open commodity derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.

Commodity Price RiskDuring
As of June 30, 2020, we had various open commodity derivatives. Based on the first nine months of 2017, we entered into crude oilJune 30, 2020 published NYMEX WTI and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted United States E&P sales. The following tables provide a summary of open positions as of September 30, 2017 and the weighted average price for those contracts:
Crude Oil
 20172018
 Fourth QuarterFirst QuarterSecond QuarterThird QuarterFourth Quarter
Three-Way Collars (a)





Volume (Bbls/day)50,00075,00075,00062,00062,000
Weighted average price per Bbl:




Ceiling$60.37$56.24$56.24$56.08$56.08
Floor$54.80$51.33$51.33$50.50$50.50
Sold put$47.80$44.73$44.73$43.61$43.61
Swaps (b)(c)





Volume (Bbls/day)20,000————
Weighted average price per Bbl$51.37————
Sold call options (d)





Volume (Bbls/day)35,000————
Weighted average price per Bbl$61.91————
Basis Swaps (e)





Volume (Bbls/day)—5,0005,00010,00010,000
Weighted average price per Bbl—$(0.60)$(0.60)$(0.67)$(0.67)
(a)
Between September 30, 2017 and October 30, 2017, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $58.07, a floor price of $53.70, and a sold put price of $47.00.
(b)
The counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $52.67 per Bbl indexed to NYMEX WTI, which is exercisable on December 29, 2017. If the counterparties exercise, the term of the fixed-price swaps would be from January - June 2018 and, if all such options are exercised, for 10,000 Bbls/day.
(c)
Between September 30, 2017 and October 30, 2017, we entered into 40,000 Bbls/day of fixed-price swaps for November - December 2017 with a weighted average price of $54.11.
(d)
Call options settle monthly.
(e)
The basis differential price is between WTI Midland and WTI Cushing.
Natural Gas
 20172018
 Fourth QuarterFirst QuarterSecond QuarterThird QuarterFourth Quarter
Three-Way Collars




Volume (MMBtu/day)120,000200,000160,000160,000160,000
Weighted average price per MMBtu:




Ceiling$3.71$3.79$3.61$3.61$3.61
Floor$3.14$3.08$3.00$3.00$3.00
Sold put$2.60$2.55$2.50$2.50$2.50
Swaps




Volume (MMBtu/day)20,000————
Weighted average price per MMBtu$2.93————



The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations offutures prices, a hypothetical 10% change (per bbl for crude oil, per MMbtu for gas) would change the fair values of our $79 million net asset position to the following:
(In millions)Hypothetical Price Increase of 10%Hypothetical Price Decrease of 10%
Derivative asset - Crude Oil$57  $93  
Derivative asset (liability) - Natural Gas(4) 5  
Total$53  $98  

Interest Rate Risk
        At June 30, 2020 our portfolio of current and long-term debt is comprised of fixed-rate instruments with an outstanding balance of $5.5 billion. Our sensitivity to interest rate movements and corresponding changes in NYMEX WTIthe fair value of our fixed-rate debt portfolio affects our results of operations and Henry Hubcash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value.

At June 30, 2020, we had forward starting interest rate swap agreements with a total notional of $1.1 billion designated as cash flow hedges. We utilize cash flow hedges to manage our exposure to interest rate movements by utilizing interest rate swap agreements to hedge variations in cash flows related to (1) the 1-month LIBOR component of future lease payments on our open commodity derivative instruments as of September 30, 2017.
(In millions)Hypothetical Price Increase of 10%Hypothetical Price Decrease of 10%
   
Crude oil derivatives$(112)$92
Natural gas derivatives(12)11
Total$(124)$103

Interest Rate Risk Sensitivity analysis offuture Houston office and (2) the incremental effect of abenchmark LIBOR index for our debt due in 2022 and 2025. A hypothetical 10% decreasechange in interest rates on financial assets and liabilitieswould change the fair values of our $24 million net liability position to the following as of SeptemberJune 30, 2017, is provided in the following table.2020:
(In millions)Hypothetical Interest Rate Increase of 10%Hypothetical Interest Rate Decrease of 10%
Interest rate cash flow hedges$16  $32  
(In millions)Fair Value Incremental Change in Fair Value
Financial assets (liabilities): (a)
   
Long term debt, including amounts due within one year$(6,781)
(b)(c) 
$(283)
(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 SeptemberJune 30, 2017.2020.  
During the first ninesix months of 2017,2020, 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.

45


Part II – OTHER INFORMATION
Item 1. Legal Proceedings
We are a defendantThere have been no significant changes to Item 3. Legal Proceedings 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 effectour 2019 Annual Report on our consolidated financial position, results of operations or cash flows.  
Form 10-K. See Note 2124 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings.
The following is a summary of certain proceedings involving us that were pending or contemplated as of September 30, 2017, under federal, state and international environmental laws:
In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations.  We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000, which was reduced to $130,500 under the terms of the settlement agreement by mitigating corrective actions.  We paid the penalty in September 2017 and do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows. 

Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discussed in Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K. There have been no material changes to the risk factors underfrom those listed in Item 1A. Risk Factors in our 20162019 Annual Report on Form 10-K.10-K, except as noted below.

Our business, financial conditions and results of operations have been adversely affected and may continue to be adversely affected by the recent COVID-19 global pandemic and the recent energy industry developments.
Any widespread outbreaks of contagious diseases have the potential to impact our business and operations. The recent novel coronavirus global pandemic, known as COVID-19, has had an adverse impact on our business, financial condition and results of operations and such impacts could be material. The current effects of COVID-19 include a substantial decline in demand for crude oil, condensate, NGLs, natural gas and other petroleum hydrocarbons, along with a corresponding deterioration in prices. In addition, COVID-19, combined with the resulting economic downturn could have a negative impact on our operations; impact the ability of our counterparties to perform their obligations; result in voluntary and involuntary curtailments, delays or cancellations of certain drilling activities; impair the quantity or value of our reserves; result in transportation and storage capacity restraints; cause shortages of key personnel, including employees, contractors and subcontractors; interrupt global supply chains; increase impairments and associated charges to our earnings; impact our cash on hand, uses of cash and cause a decrease to our financial flexibility and liquidity. In addition, the risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely as we plan a process to phase employees to return to the office. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures.

The impacts of COVID-19 could be further exacerbated by the Organization of the Petroleum Exporting Countries (OPEC) and Russia regarding crude oil production cuts. Negotiations in April 2020 with OPEC and Russia resulted in an agreement to reduce production volumes; however, a failure to abide by these agreed upon crude oil production cuts may further destabilize the global oil market. The extent to which COVID-19 or the recent energy industry developments will impact our business and our financial results will depend on future developments, which are highly uncertain and cannot be predicted. As a result, at the time of this filing, it is not possible to predict the overall impact of COVID-19 or the recent energy industry developments on our business, liquidity, capital resources and financial results.

We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in law, regulations or requirements or initiatives, including those addressing environmental, health, safety, or security or the impact of global climate change, air emissions or water management, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Our businesses are currently subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions, including carbon dioxide and methane, and the protection of endangered species as well as laws, regulations, and other requirements relating to public and employee safety and health and to facility security. Additionally, states in which we operate may: impose additional regulations legislation, or requirements, such as the proposed methane emission rules in New Mexico; begin initiatives addressing the impact of global climate change, air emissions or water management; or we may become subject to additional regulations based on questions of sovereignty between the states and Native American tribes. We have incurred and may continue to incur capital, operating and maintenance, and remediation expenditures as a result of these laws, regulations, and other requirements or initiatives that are being considered or otherwise implemented. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results could be adversely affected. The specific impact of these laws, regulations, and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in
46

connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations, and other requirements could result in civil penalties or criminal fines and other enforcement actions against us.

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Our operations result in greenhouse gas emissions. Currently, various legislative or regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in the U.S. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered. Finalization of new legislation, regulations or international agreements in the future could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and condensate, NGLs and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.

Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.

The marketability of our production depends in part on the availability, proximity, and capacity of gathering and transportation pipeline facilities, rail cars, trucks and vessels. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our crude oil and condensate, NGLs and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production. For example, in early July, a U.S. district court ordered the Dakota Access Pipeline to halt oil flow and empty the pipeline within 30 days because the United States Army Corps of Engineers did not conduct a full Environmental Impact Statement.  Though a federal appellate court has administratively stayed the shutdown, if a shutdown occurs, we will need to use alternative means to transport approximately 10,000 bpd (on a net basis) of our Bakken oil. A shutdown could also have an impact on safety (because it would require the use of additional trucks, rail cars and personnel) and our Bakken price differentials, all of which could adversely affect the results of our operations. In addition, both the cost and availability of pipelines, rail cars, trucks, or vessels to transport our production could be adversely impacted by new and expected state or federal regulations relating to transportation of crude oil.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about repurchasespurchases by Marathon Oil ofand its common stockaffiliated purchaser, during the quarter ended SeptemberJune 30, 2017.2020 of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:
Period
Total Number of Shares Purchased(a)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)
04/01/2020 - 04/30/202021,168  $3.65  —  $1,320,335,751  
05/01/2020 - 05/31/20201,718  $5.50  —  $1,320,335,751  
06/01/2020 - 06/30/20201,050  $5.69  —  $1,320,335,751  
Total23,936  $3.88  —  
(a)23,936 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.
As of June 30, 2020, we have repurchased 191 million common shares at a cost of approximately $5.9 billion, excluding transaction fees and commissions. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. In connection with the economic downturn, during the second quarter of 2020, the Company temporarily suspended the share repurchase program. Shares repurchased as of June 30, 2020 were held as treasury stock.
Period
Total Number of
Shares
Purchased(a)
 
Average
Price Paid
per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs(b)
 
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs(b)
07/01/17 - 07/31/17775
 $12.08 —
 $1,500,285,529
08/01/17 - 08/31/17476
 $12.05 —
 $1,500,285,529
09/01/17 - 09/30/1789
 $11.21 —
 $1,500,285,529
Total1,340
 $12.01 —
  
(a)
1,340 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, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of September 30, 2017 is $1.5 billion. No repurchases were made under the program in the third quarter of 2017.
Item 6.  Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.

47


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.
November 2, 2017August 6, 2020MARATHON OIL CORPORATION
By:/s/ Gary E. Wilson
Gary E. Wilson
Vice President, Controller and Chief Accounting Officer
(Duly Authorized Officer)

48


Exhibit Index
  Incorporated by Reference
(File No. 001-05153, unless otherwise indicated)
Exhibit NumberExhibit DescriptionFormExhibitFiling Date
3.1
Restated Certificate of Incorporation of Marathon Oil Corporation
8-K3.16/1/2018
3.2
Marathon Oil Corporation By-laws (amended and restated as of February 24, 2016)
10-Q3.28/4/2016
3.3
Specimen of Common Stock Certificate
10-K3.32/28/2014
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-K4.22/28/2014
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 - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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
104*
Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101
*Filed herewith.
†Management contract or compensatory plan or arrangement.

   Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number Exhibit DescriptionForm 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 4.2 2/28/2014 
4.2 
Terms of the 4.400% Senior Notes due 2027
8-K 4.2 7/24/2017 
4.3 
Form of 4.400% Senior Notes due 2027
8-K 4.3 7/24/2017 
10.2 
Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.
10-Q 10.2 8/3/2017 
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.