Document


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 June 30, 2017
 
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 1-5153
mro_logoa33.jpg
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
Delaware
 
25-0996816
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, TX  77056-2723
(Address of principal executive offices)

(713) 629-6600
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes 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 filer þ
Accelerated filer o     
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o   
Emerging growth company o
 
 
 

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 849,834,915 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2017.



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 2016 Annual Report on Form 10-K.

 
Table of Contents
 
 
 
Page
 
 
 
 
 
 
 
 
 
 


1


Part I - Financial Information
Item 1. Financial Statements

MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(In millions, except per share data)
2017
 
2016
 
2017
 
2016
Revenues and other income:
 
 
 
 
 
 
 
Sales and other operating revenues, including related party
$
958

 
$
685

 
$
1,912

 
$
1,251

Marketing revenues
35

 
76

 
69

 
122

Income from equity method investments
51

 
37

 
120

 
51

Net gain (loss) on disposal of assets
6

 
294

 
7

 
234

Other income
9

 
11

 
23

 
15

Total revenues and other income
1,059

 
1,103

 
2,131

 
1,673

Costs and expenses:
 

 
 

 
 
 
 

Production
176

 
185

 
327

 
372

Marketing, including purchases from related parties
38

 
75

 
72

 
121

Other operating
111

 
87

 
200

 
190

Exploration
30

 
182

 
58

 
206

Depreciation, depletion and amortization
592

 
512

 
1,148

 
1,061

Impairments
—

 
—

 
4

 
1

Taxes other than income
45

 
35

 
84

 
78

General and administrative
93

 
131

 
202

 
282

Total costs and expenses
1,085

 
1,207

 
2,095

 
2,311

Income (loss) from operations
(26
)
 
(104
)
 
36

 
(638
)
Net interest and other
(86
)
 
(88
)
 
(164
)
 
(167
)
Income (loss) from continuing operations before income taxes
(112
)
 
(192
)
 
(128
)
 
(805
)
Provision (benefit) for income taxes
41

 
(54
)
 
75

 
(307
)
Income (loss) from continuing operations
(153
)
 
(138
)
 
(203
)
 
(498
)
Income (loss) from discontinued operations
14

 
(32
)
 
(4,893
)
 
(79
)
Net income (loss)
$
(139
)
 
$
(170
)
 
$
(5,096
)
 
$
(577
)
Per basic share:
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
(0.18
)
 
$
(0.16
)
 
$
(0.24
)
 
$
(0.63
)
Income (loss) from discontinued operations
$
0.02

 
$
(0.04
)
 
$
(5.76
)
 
$
(0.10
)
Net income (loss)
$
(0.16
)
 
$
(0.20
)
 
$
(6.00
)
 
$
(0.73
)
Per diluted share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.18
)
 
$
(0.16
)
 
$
(0.24
)
 
$
(0.63
)
Income (loss) from discontinued operations
$
0.02

 
$
(0.04
)
 
$
(5.76
)
 
$
(0.10
)
Net income (loss)
$
(0.16
)
 
$
(0.20
)
 
$
(6.00
)
 
$
(0.73
)
Dividends per share
$
0.05

 
$
0.05

 
$
0.10

 
$
0.10

Weighted average common shares outstanding:
 

 
 

 
 

 
 

Basic
850

 
848

 
850

 
790

Diluted
850

 
848

 
850

 
790

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

2


MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
(In millions)
2017
 
2016
 
2017
 
2016
Net income (loss)
$
(139
)
 
$
(170
)
 
$
(5,096
)
 
$
(577
)
Other comprehensive income (loss)
 
 
 

 
 

 
 

Postretirement and postemployment plans
 

 
 

 
 

 
 

Change in actuarial loss and other
8

 
19

 
12

 
(5
)
Income tax provision (benefit)
—

 
(7
)
 
—

 
2

Postretirement and postemployment plans, net of tax
8

 
12

 
12

 
(3
)
Derivative hedges
 
 
 
 
 
 
 
Net unrecognized gain (loss)
(14
)
 
—

 
(13
)
 
—

Income tax provision
—

 
—

 
—

 
—

Derivative hedges, net of tax
(14
)
 
—

 
(13
)
 
—

Foreign currency hedges
 

 
 

 
 

 
 

Net recognized gain reclassified to discontinued operations
—

 
—

 
34

 
—

Income tax benefit (provision)
—

 
—

 
(4
)
 
—

Foreign currency hedges, net of tax
—

 
—

 
30

 
—

Other, Net of Tax
—

 
(2
)
 
—

 
(2
)
 
 
 
 
 
 
 
 
Other comprehensive income (loss)
(6
)
 
10

 
29

 
(5
)
Comprehensive income (loss)
$
(145
)

$
(160
)

$
(5,067
)

$
(582
)
 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 per share data)
2017
 
2016
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,614

 
$
2,488

Receivables, less reserve of $5 and $6
767

 
748

Notes receivable
742

 
—

Inventories
140

 
136

Other current assets
160

 
66

Current assets held for sale
1

 
227

Total current assets
4,424

 
3,665

Equity method investments
821

 
931

Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,238 and $20,255
18,337

 
16,727

Goodwill
115

 
115

Other noncurrent assets
543

 
558

Noncurrent assets held for sale
1

 
9,098

Total assets
$
24,241

 
$
31,094

Liabilities
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
1,158

 
$
967

Payroll and benefits payable
92

 
129

Accrued taxes
78

 
94

Other current liabilities
206

 
243

Long-term debt due within one year
548

 
686

Current liabilities held for sale
—

 
121

Total current liabilities
2,082

 
2,240

Long-term debt
6,715

 
6,581

Deferred tax liabilities
839

 
769

Defined benefit postretirement plan obligations
340

 
345

Asset retirement obligations
1,642

 
1,602

Deferred credits and other liabilities
211

 
225

Noncurrent liabilities held for sale
7

 
1,791

Total liabilities
11,836

 
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
(3,318
)
 
(3,431
)
Additional paid-in capital
7,349

 
7,446

Retained earnings
7,491

 
12,672

Accumulated other comprehensive loss
(54
)
 
(83
)
Total stockholders' equity
12,405

 
17,541

Total liabilities and stockholders' equity
$
24,241

 
$
31,094

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

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
 
Six Months Ended
 
June 30,
(In millions)
2017
 
2016
Operating activities:
 

 
 

Net income (loss)
$
(5,096
)
 
$
(577
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Discontinued operations
4,893

 
79

Depreciation, depletion and amortization
1,148

 
1,061

Exploratory dry well costs and unproved property impairments
45

 
159

Net (gain) loss on disposal of assets
(7
)
 
(234
)
Deferred income taxes
38

 
(352
)
Net (gain) loss on derivative instruments
(140
)
 
90

Net cash received (paid) in settlement of derivative instruments
3

 
44

Stock based compensation
26

 
26

Equity method investments, net
61

 
22

Changes in:
 
 
 

Current receivables
(15
)
 
92

Inventories
(5
)
 
25

Current accounts payable and accrued liabilities
(41
)
 
(207
)
All other operating, net
13

 
39

Net cash provided by operating activities from continuing operations
923

 
267

Investing activities:
 

 
 

Additions to property, plant and equipment
(775
)
 
(728
)
Acquisitions, net of cash acquired
(1,828
)
 
—

Deposits for acquisitions
—

 
(89
)
Disposal of assets, net of cash transferred to buyer
1,726

 
758

Equity method investments - return of capital
49

 
37

All other investing, net
(5
)
 
2

Net cash used in investing activities from continuing operations
(833
)
 
(20
)
Financing activities:
 

 
 

Debt repayments
(1
)
 
—

Common stock issuance
—

 
1,236

Purchases of common stock
(10
)
 
(4
)
Dividends paid
(85
)
 
(77
)
Net cash provided by (used in) financing activities
(96
)
 
1,155

Cash Flow from Discontinued Operations:
 
 
 
Operating activities
141

 
(11
)
Investing activities
(13
)
 
(25
)
Changes in cash included in current assets held for sale
2

 
36

Net increase in cash and cash equivalents of discontinued operations
130

 
—

Effect of exchange rate on cash and cash equivalents
2

 
(3
)
Net increase (decrease) in cash and cash equivalents
126

 
1,399

Cash and cash equivalents at beginning of period
2,488

 
1,119

Cash and cash equivalents at end of period
$
2,614

 
$
2,518

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

5
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 2016 Annual Report on Form 10-K.  The results of operations for the second quarter and first six months of 2017 are not necessarily indicative of the results to be expected for the full year.
As a result of the announcement to divest our Canadian business in the first 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 presented 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. This transaction closed in the second quarter of 2017. 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 quarter 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. See Note 2 for additional discussion. 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 six months ended June 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 Yet Adopted
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. 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 are evaluating the provisions of this accounting standards update and assessing the impact it may have on our results of operations, financial position, or cash flows.
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.

6
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 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. 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 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 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 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 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. The standard requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted 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.
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 should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In 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”). While early adoption is permitted, we plan to 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 six months ended June 30, 2017, we estimate this impact to be

7
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



approximately $50 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.
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 River 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.

4.
Income (Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding.  Diluted income per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below exclude 12 million stock options for the three and six month periods ended June 30, 2017 and 14 million stock options for the three and six month periods ended June 30, 2016 that were antidilutive.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions, except per share data)
2017
 
2016
 
2017
 
2016
Income (loss) from operations
$
(153
)
 
$
(138
)
 
$
(203
)
 
$
(498
)
Income (loss) from discontinued operations
14

 
(32
)
 
(4,893
)
 
(79
)
Net income (loss)
$
(139
)
 
$
(170
)
 
$
(5,096
)
 
$
(577
)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding
850

 
848

 
850

 
790

Per basic share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.18
)
 
$
(0.16
)
 
$
(0.24
)
 
$
(0.63
)
Income (loss) from discontinued operations
$
0.02

 
$
(0.04
)
 
$
(5.76
)
 
$
(0.10
)
Net income
$
(0.16
)
 
$
(0.20
)
 
$
(6.00
)
 
$
(0.73
)
Per diluted share:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
(0.18
)
 
$
(0.16
)
 
$
(0.24
)
 
$
(0.63
)
Income (loss) from discontinued operations
$
0.02

 
$
(0.04
)
 
$
(5.76
)
 
$
(0.10
)
Net income
$
(0.16
)
 
$
(0.20
)
 
$
(6.00
)
 
$
(0.73
)

8
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



5. Acquisitions
2017 - United States E&P
In the second quarter of 2017 we closed on our acquisitions to acquire approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin 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 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.
2016 - United States E&P
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.
6.
Dispositions
Oil Sands Mining Segment
On May 31, 2017 we closed on the sale of our Canadian business, which includes our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million. We initially recorded these notes receivable at fair value and, in subsequent periods, will report them at amortized cost. See Note 13 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 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.
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:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions)
 
2017
 
2016
 
2017
 
2016
Total sales and other revenues and other income
 
$
173

 
$
199

 
$
431

 
$
359

Net gain (loss) on disposal of assets
 
(43
)
 
—

 
(43
)
 
—

Total revenues and other income
 
130

 
199

 
388

 
359

Costs and expenses:
 
 
 
 
 
 
 
 
Production expenses
 
103

 
165

 
254

 
306

Depreciation, depletion and amortization
 
1

 
49

 
40

 
109

Impairments
 
—

 
—

 
6,636

 
—

Other
 
12

 
31

 
25

 
60

Total costs and expenses
 
116

 
245

 
6,955

 
475

Pretax income (loss) from discontinued operations
 
14

 
(46
)
 
(6,567
)
 
(116
)
Provision (benefit) for income taxes
 
—

 
(14
)
 
(1,674
)
 
(37
)
Income (loss) from discontinued operations
 
$
14

 
$
(32
)
 
$
(4,893
)
 
$
(79
)

9
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



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 June 30, 2017 and December 31, 2016:
 
 
June 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
 
1

 
1

Total current assets held for sale
 
$
1

 
$
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
 
1

 
1

Total noncurrent assets held for sale
 
$
1

 
$
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
 
7

 
7

Total noncurrent liabilities held for sale
 
$
7

 
$
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 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.

10
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



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, with the remaining Piceance basin asset sale expected to close in the second half of 2017.
7.    Segment Information
  We have two reportable operating segments. Both of these segments are organized and managed based upon geographic location and the nature of the products and services offered.
•
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 – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and 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 segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.
As discussed in Note 6, we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases, in the second quarter 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.
 
Three Months Ended June 30, 2017
 
 
Not Allocated
 
 
(In millions)
U.S. E&P
 
Int'l E&P
 
to Segments
 
Total
Sales and other operating revenues
$
695

 
$
220

 
$
43

(c) 
$
958

Marketing revenues
7

 
28

 
—

 
35

Total revenues
702

 
248

 
43

 
993

Income from equity method investments
—

 
51

 
—

 
51

Net gain on disposal of assets and other income
2

 
4

 
9

 
15

Less:
 
 
 
 
 
 
 
Production expenses
118

 
58

 
—

 
176

Marketing costs
9

 
29

 
—

 
38

Exploration expenses
30

 
—

 
—


30

Depreciation, depletion and amortization
495

 
89

 
8

 
592

Other expenses (a)
126

 
22

 
56

(d) 
204

Taxes other than income
33

 
—

 
12

 
45

Net interest and other
—

 
—

 
86

 
86

Income tax provision (benefit)
—

 
46

 
(5
)
 
41

Segment income (loss) / Income (loss) from continuing operations
$
(107
)
 
$
59

 
$
(105
)
 
$
(153
)
Capital expenditures (b)
$
575

 
$
14

 
$
10

 
$
599

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on commodity derivative instruments.

11
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



(d) 
Includes pension settlement loss of $3 million. (See Note 8.)
 
Three Months Ended June 30, 2016
 
 
Not Allocated
 
 
(In millions)
U.S. E&P
 
Int'l E&P
 
to Segments
 
Total
Sales and other operating revenues
$
617

 
$
159

 
$
(91
)
(c) 
$
685

Marketing revenues
53

 
23

 
—

 
76

Total revenues
670

 
182

 
(91
)
 
761

Income from equity method investments
—

 
37

 
—

 
37

Net gain on disposal of assets and other income
2

 
7

 
296

(d) 
305

Less:
 
 
 
 
 
 
 
Production expenses
129

 
56

 
—

 
185

Marketing costs
52

 
23

 
—

 
75

Exploration expenses
37

 
4

 
141

(e) 
182

Depreciation, depletion and amortization
433

 
68

 
11

 
512

Other expenses (a)
97

 
22

 
99

(f) 
218

Taxes other than income
35

 
—

 
—

 
35

Net interest and other
—

 
—

 
88

 
88

Income tax provision (benefit)
(41
)
 
(2
)
 
(11
)
 
(54
)
Segment income (loss) / Income (loss) from continuing operations
$
(70
)
 
$
55

 
$
(123
)
 
$
(138
)
Capital expenditures (b)
$
153

 
$
12

 
$
5

 
$
170

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized loss on commodity derivative instruments.
(d) 
Primarily related to partial sale of Wyoming upstream and midstream assets. (See Note 6.)
(e) 
Impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases.
(f) 
Includes pension settlement loss of $31 million (See Note 8).

12
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



 
Six Months Ended June 30, 2017
 
 
Not Allocated
 
 
(In millions)
U.S. E&P
 
Int'l E&P
 
to Segments
 
Total
Sales and other operating revenues
$
1,369

 
$
423

 
$
120

(c) 
$
1,912

Marketing revenues
13

 
56

 
—

 
69

Total revenues
1,382

 
479

 
120

 
1,981

Income from equity method investments
—

 
120

 
—

 
120

Net gain on disposal of assets and other income
7

 
14

 
9

 
30

Less:
 
 
 
 
 
 
 
Production expenses
227

 
100

 
—

 
327

Marketing costs
16

 
56

 
—

 
72

Exploration expenses
56

 
2

 
—


58

Depreciation, depletion and amortization
967

 
164

 
17

 
1,148

Impairments
4

 
—

 
—

 
4

Other expenses (a)
233

 
43

 
126

(d) 
402

Taxes other than income
72

 
—

 
12

 
84

Net interest and other
—

 
—

 
164

 
164

Income tax provision (benefit)
—

 
96

 
(21
)
 
75

Segment income (loss) / Income (loss) from continuing operations
$
(186
)
 
$
152

 
$
(169
)
 
$
(203
)
Capital expenditures (b)
$
924

 
$
23

 
$
11

 
$
958

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized gain on commodity derivative instruments.
(d) 
Includes pension settlement loss of $17 million. (See Note 8.)
 
Six Months Ended June 30, 2016
 
 
Not Allocated
 
 
(In millions)
U.S. E&P
 
Int'l E&P
 
to Segments
 
Total
Sales and other operating revenues
$
1,110

 
$
255

 
$
(114
)
(c) 
$
1,251

Marketing revenues
84

 
38

 
—

 
122

Total revenues
1,194

 
293

 
(114
)
 
1,373

Income from equity method investments
—

 
51

 
—

 
51

Net gain on disposal of assets and other income
3

 
13

 
233

(d) 
249

Less:
 
 
 
 
 
 
 
Production expenses
263

 
109

 
—

 
372

Marketing costs
84

 
37

 
—

 
121

Exploration expenses
55

 
10

 
141

(e) 
206

Depreciation, depletion and amortization
920

 
118

 
23

 
1,061

Impairments
1

 
—

 
—

 
1

Other expenses (a)
215

 
38

 
219

(f) 
472

Taxes other than income
77

 
—

 
1

 
78

Net interest and other
—

 
—

 
167

 
167

Income tax provision (benefit)
(153
)
 
(14
)
 
(140
)
 
(307
)
Segment income (loss) / Income (loss) from continuing operations
$
(265
)
 
$
59

 
$
(292
)
 
$
(498
)
Capital expenditures (b)
$
468

 
$
44

 
$
8

 
$
520

(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized loss on commodity derivative instruments.

13
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



(d) 
Related to net gain on disposal of assets (see Note 6).
(e) 
Impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases.
(f) 
Includes pension settlement loss of $79 million and severance related expenses associated with workforce reductions of $8 million (see Note 8).

8.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
 
Three Months Ended June 30,
  
Pension Benefits
 
Other Benefits
(In millions)
2017
 
2016
 
2017
 
2016
Service cost
$
5

 
$
6

 
$
—

 
$
1

Interest cost
7

 
10

 
2

 
2

Expected return on plan assets
(10
)
 
(13
)
 
—

 
—

Amortization:
 

 
 

 
 

 
 

– prior service cost (credit)
(2
)
 
(3
)
 
(1
)
 
(1
)
– actuarial loss
2

 
4

 
—

 
—

Net settlement loss (a)
3

 
31

 
—

 
—

Net periodic benefit cost
$
5

 
$
35

 
$
1

 
$
2

 
Six Months Ended June 30,
  
Pension Benefits
 
Other Benefits
(In millions)
2017
 
2016
 
2017
 
2016
Service cost
$
11

 
$
12

 
$
1

 
$
2

Interest cost
15

 
21

 
4

 
5

Expected return on plan assets
(22
)
 
(28
)
 
—

 
—

Amortization:
 
 
 

 
 

 
 

– prior service cost (credit)
(4
)
 
(5
)
 
(3
)
 
(2
)
– actuarial loss
4

 
7

 
—

 
—

Net settlement loss (a)
17

 
79

 
—

 
—

Net periodic benefit cost
$
21


$
86


$
2


$
5

(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 six months of 2017, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans’ assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.
During the first six months of 2017, we made contributions of $27 million to our funded pension plans and we expect to make additional contributions up to an estimated $33 million over the remainder of 2017.  During the first six months of 2017, we made payments of $8 million and $12 million related to unfunded pension plans and other postretirement benefit plans, respectively.

14
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



9.    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. For the second quarter and first six months of 2017 and 2016, our effective income tax rates on continuing operations were as follows:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions)
 
2017
 
2016
 
2017
 
2016
Total pre-tax income (loss) from continuing operations
 
$
(112
)
 
$
(192
)
 
$
(128
)
 
$
(805
)
Total income tax expense (benefit)
 
$
41

 
$
(54
)
 
$
75

 
$
(307
)
Effective income tax expense (benefit) rate on continuing operations
 
37
%
 
(28
)%
 
59
%
 
(38
)%
 
 
 
 
 
 
 
 
 
Income taxes at the statutory tax rate of 35%
 
$
(39
)
 
$
(67
)
 
$
(45
)
 
$
(282
)
Effects of foreign operations
 
2

 
5

 
(2
)
 
(30
)
Adjustments to valuation allowances
 
76

 
5

 
133

 
5

State income taxes
 
—

 
3

 
(13
)
 
(3
)
Other federal tax effects
 
2

 
—

 
2

 
3

Income tax expense (benefit) on continuing operations
 
$
41

 
$
(54
)
 
$
75

 
$
(307
)
Income tax expense for the second quarter and first six months of 2017 was impacted by a full valuation allowance on our 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 $32 million in the second quarter and $77 million in the first six months of 2017 compared to a benefit of $10 million and $21 million for the same periods last year.
In the first six 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 June 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 20, 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 second quarter and first six months of 2017 and 2016, was driven by the full valuation allowance on our 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 second quarter and first six months of 2017 totaled tax expense of $2 million for three months ended June 30, 2017 and a tax benefit of $2 million for the first six 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 second quarter and the first six months of 2017 and 2016.  For the second quarter and the first six 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 a benefit of 25% for the second quarter of 2017 and 2016. Excluding Libya, the effective income tax expense and benefit rates would be a benefit of 1% and 36% for the first six months of 2017 and 2016.
We expect to be in a cumulative loss position in 2017, and as a result we have placed a full valuation allowance on our federal deferred tax assets. In the second quarter and first six months of 2017 this valuation allowance was $76 million and

15
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



$133 million. During 2017 we expect to realize no tax benefit on any 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 federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017.
10.   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.
 
June 30,
 
December 31,
(In millions)
2017
 
2016
Crude oil and natural gas
$
11

 
$
6

Supplies and other items
129

 
130

Inventories
$
140

 
$
136

11.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
 
June 30,
 
December 31,
(In millions)
2017
 
2016
United States E&P
$
15,888

 
$
14,158

International E&P
2,358

 
2,470

Corporate
91

 
99

Net property, plant and equipment
$
18,337


$
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 six months of 2017, except for a brief interruption in March 2017 due to civil unrest.
As of June 30, 2017, our net property, plant and equipment investment in Libya is $767 million, and total proved reserves (unaudited) in Libya as of December 31, 2016 are 206 million barrels of oil equivalent (“mmboe”). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of $767 million by a significant amount.
Exploratory well costs capitalized greater than one year after completion of drilling were $96 million and $118 million as of June 30, 2017 and December 31, 2016. The decrease in costs of $22 million was primarily due to an April 2017 approval by the host government in E.G. to develop Block D offshore E.G. through unitization with the Alba field.  As such, the $22 million exploratory well costs capitalized greater than one year after completion associated with the Corona well are no longer being deferred.

16
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



12. Impairments and Exploration Expenses
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. See Note 6 for relevant detail regarding dispositions.

The following table summarizes the components of exploration expenses:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions)
2017
 
2016
 
2017
 
2016
Exploration Expenses
 
 
 
 
 
 
 
Unproved property impairments
$
25

 
$
133

 
$
45

 
$
144

Dry well costs
—

 
15

 
—

 
15

Geological and geophysical
—

 
—

 
1

 
—

Other
5

 
34

 
12

 
47

Total exploration expenses
$
30

 
$
182

 
$
58

 
$
206


13.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016 by fair value hierarchy level.
 
June 30, 2017
(In millions)
Level 1
 
Level 2
 
Level 3
 
Total
Derivative instruments, assets
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
60

 
$
—

 
$
60

     Interest rate
—

 
54

 
—

 
54

Derivative instruments, assets
$
—

 
$
114

 
$
—

 
$
114

Derivative instruments, liabilities
 
 
 
 
 
 
 
     Commodity (a)
$
—

 
$
—

 
$
—

 
$
—

Derivative instruments, liabilities
$
—

 
$
—

 
$
—

 
$
—

(a)  
Derivative instruments are recorded on a net basis in our balance sheet. See Note 14.

 
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 14.
Commodity derivatives include three-way collars, call options and swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. Inputs to the models include commodity prices, interest rates, 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.

17
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Both our interest rate swaps and 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 14 for additional discussion of the types of derivative instruments we use.
Fair Values - Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. As of June 30, 2017 we have $115 million of goodwill associated with our International E&P reporting unit. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers 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 valuations methodologies represent Level 3 fair value measurements. We performed our annual impairment test in April 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.
Fair Values- Nonrecurring
The following discusses the values of assets measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a 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 Note 6 for relevant detail regarding dispositions.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, 2017 and December 31, 2016.
 
June 30, 2017
 
December 31, 2016
 
Fair
 
Carrying
 
Fair
 
Carrying
(In millions)
Value
 
Amount
 
Value
 
Amount
Financial assets
 
 
 
 
 
 
 
Current assets (a)
$
753

 
$
753

 
$
7

 
$
7

Other noncurrent assets
104

 
107

 
105

 
108

Total financial assets  
$
857

 
$
860

 
$
112

 
$
115

Financial liabilities
 

 
 

 
 

 
 

     Other current liabilities
$
43

 
$
54

 
$
68

 
$
75

     Long-term debt, including current portion (b)
7,451

 
7,293

 
7,449

 
7,292

Deferred credits and other liabilities
110

 
103

 
114

 
107

Total financial liabilities  
$
7,604

 
$
7,450

 
$
7,631

 
$
7,474


18
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



(a)    Includes our two notes receivable relating to the sale of our Canadian business as of June 30, 2017, see note 6 for further information.
(b) Excludes capital leases, debt issuance costs and interest rate swap adjustments.
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.
Most of our long-term debt instruments are publicly traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
14. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 13. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets.
 
June 30, 2017
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
1

 
$
—

 
$
1

 
Other current assets
Total Designated Hedges
$
1

 
$
—

 
$
1

 
 
 
 
 
 
 
 
 
 
Not Designated as Hedges
 
 
 
 
 
 
 
     Interest rate
$
53

 
$
—

 
$
53

 
Other current assets
   Commodity
57

 
—

 
57

 
Other current assets
   Commodity
3

 
—

 
3

 
Other noncurrent assets
Total Not Designated as Hedges
$
113

 
$
—

 
$
113

 
 
     Total
$
114


$
—

 
$
114

 
 

 
December 31, 2016
 
 
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Fair Value Hedges
 
 
 
 
 
 
 
     Interest rate
$
3

 
$
—

 
$
3

 
Other current assets
     Interest rate
1

 
—

 
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

 
 


19
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 
June 30, 2017
 
December 31, 2016
 
Aggregate Notional Amount
Weighted Average, LIBOR
 
Aggregate Notional Amount
Weighted Average, LIBOR
Maturity Dates
(in millions)
Floating Rate
 
(in millions)
Floating Rate
October 1, 2017
$
600

5.54
%
 
$
600

5.10
%
March 15, 2018
$
300

5.49
%
 
$
300

5.04
%
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.

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 are 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. The occurrence of the forecasted transaction was probable at June 30, 2017 and each respective derivative contract can be tied to an anticipated underlying dollar notional amount. During the second quarter of 2017 we de-designated the forward starting interest rate swaps previously designated as cash flow hedges resulting in a mark-to-market gain of $3 million, in net interest and other, at June 30, 2017, of which $1 million was reclassified from other comprehensive income.
  
The following table presents, by maturity date, information about our forward starting interest rate swap agreements, including the rate.
 
June 30, 2017
 
December 31, 2016
 
Aggregate Notional Amount
Weighted Average, LIBOR
 
Aggregate Notional Amount
Weighted Average, LIBOR
Maturity Dates
(in millions)
Fixed Rate
 
(in millions)
Fixed Rate
March 15, 2018
$750
1.57%
 
$750
1.57%
The following table sets forth the net impact of the forward starting interest rates swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(In millions)
2017
 
2016
 
2017
 
2016
Interest Rate Swaps
 
 
 
 
 
 
 
  Beginning balance
$
61

 
$
—

 
$
60

 
$
—

Change in fair value recognized in other comprehensive income
(14
)
 
—

 
(13
)
 
—

  Reclassification from other comprehensive income
(1
)
 
—

 
(1
)
 
—

  Ending balance
$
46

 
$
—

 
$
46

 
$
—

At June 30, 2017, accumulated other comprehensive income included deferred gains of $46 million related to the de-designated forward starting interest rate swaps previously designated as cash flow hedges. As of June 30, 2017, we expected to reclassify this amount into earnings as an adjustment to net interest and other upon the occurrence of the forecasted transaction.
In July of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes, see Note 16 for further detail. This resulted in the termination of our forward starting interest rate swaps, previously designated as cash flow hedges, with proceeds of $54 million. In the third quarter of 2017, we will recognize into earnings a gain of

20
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



approximately $47 million, in net interest and other, as we have previously reclassified into earnings a gain of $7 million primarily from other comprehensive income due to ineffectiveness.
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, 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 June 30, 2017 and the weighted average prices for those contracts:
Crude Oil
 
2017
2018
 
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
Three-Way Collars (a)
 
 
 

Volume (Bbls/day)
50,000
50,000
20,000
20,000
Weighted average price per Bbl:
 
 
 
 
Ceiling
$60.37
$60.37
$57.86
$57.86
Floor
$54.80
$54.80
$53.00
$53.00
Sold put
$47.80
$47.80
$47.00
$47.00
Sold call options (b)
 
 
 
 
Volume (Bbls/day)
35,000
35,000
—
—
Weighted average price per Bbl
$61.91
$61.91
—
—
(a) 
Subsequent to June 30, 2017, we entered into 20,000 Bbls/day of three-way collars for January - December 2018 with an average ceiling price of $55.09, a floor price of $50.00, and a sold put price of $43.00.
(b) 
Call options settle monthly.
Natural Gas
 
2017
2018
 
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Three-Way Collars
 
 
 
 
 
 
Volume (MMBtu/day)
120,000
120,000
200,000
160,000
160,000
160,000
Weighted average price per MMBtu:
 
 
 
 
 
 
Ceiling
$3.58
$3.71
$3.79
$3.61
$3.61
$3.61
Floor
$3.09
$3.14
$3.08
$3.00
$3.00
$3.00
Sold put
$2.55
$2.60
$2.55
$2.50
$2.50
$2.50
Swaps
 
 
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
—
—
—
—
Weighted average price per MMBtu
$2.93
$2.93
—
—
—
—

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 six month periods ended June 30, 2017 and 2016, respectively. The three and six month periods ended June 30, 2017 impact was a net gain of $56 million and $137 million compared to a net loss of $88 million and $90 million for the same respective period in 2016. Net settlements of commodity derivative instruments for the three and six month periods ended June 30, 2017 was $13 million and $17 million compared to $2 million and $24 million for the respective period in 2016.

21
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



15.    Incentive Based Compensation
 Stock options, restricted stock awards and restricted stock units
The following table presents a summary of activity for the first six 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, 2016
11,915,533

 

$27.71

 
6,933,533

 

$14.44

Granted
799,591

(a) 

$15.80

 
3,908,344

 

$16.37

Options Exercised/Stock Vested
(8,666
)
 

$7.22

 
(2,237,657
)
 

$17.61

Canceled
(2,009,085
)
 

$35.48

 
(529,721
)
 

$15.84

Outstanding at June 30, 2017
10,697,373

 

$25.37

 
8,074,499

 

$14.40

(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 six months of 2017, we granted 563,631 stock-based performance units to certain officers. The grant date fair value per unit was $17.75.
16.  Debt
Revolving Credit Facility
As of June 30, 2017, we had no borrowings against our $3.3 billion revolving credit facility (the “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, and maintained the Credit Facility at $3.3 billion. 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 not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of June 30, 2017, we were in compliance with this covenant with a debt-to-capitalization ratio of 37%.
Long-term debt
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 notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. We will use the net proceeds of $990 million plus existing cash on hand to redeem the following senior 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

The new issuance together with the redemption will result in a reduction in total gross debt of approximately $750 million in the third quarter of 2017.
In July 2017, we gave notice that we will redeem during the third quarter of 2017, $1.76 billion of the senior unsecured notes discussed above in accordance with their make-whole call provisions. As a result of this notice we expect to recognize into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017. See Note 14 for detail relating to the proceeds of $54 million, which will result in a gain of approximately $47 million

22
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



into earnings in the third quarter of 2017, on the termination of our forward starting interest rate swaps associated with this issuance.
As a result of the debt issuance discussed above, we reclassified $990 million of the 6.0% notes due in 2017 and 5.9% notes due in 2018 to long-term debt as we have the intent and ability to redeem them with the net proceeds received from the debt issuance. Therefore, as of June 30, 2017, we had long-term debt due within one year of $548 million.
17.  Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
(In millions)
2017
 
2016
 
2017
 
2016
 
Income Statement Line
 
 
 
 
Postretirement and postemployment plans
 
 
 
 
 
 
 
 
Amortization of actuarial loss
$
(2
)
 
$
(4
)
 
$
(4
)
 
$
(7
)
 
General and administrative
Net settlement loss
(3
)
 
(31
)
 
(17
)
 
(79
)
 
General and administrative
Derivative hedges
 
 
 
 
 
 
 
 
 
Ineffective portion of derivative hedge
(1
)
 
—

 
(1
)
 
—

 
Net interest and other
 
(6
)
 
(35
)
 
(22
)
 
(86
)
 
Income (loss) from operations
 
—

 
13

 
—

 
29

 
Benefit for income taxes
Total reclassifications to expense, net of tax
(6
)
 
(22
)
 
(22
)
 
(57
)
 
Income (loss) from continuing operations
Foreign currency hedges
 
 
 
 
 
 
 
 
 
Net recognized gain in discontinued operations, net of tax
—

 
—

 
(30
)
 
—

 
Income (loss) from discontinued operations
Total reclassifications to expense
$
(6
)
 
$
(22
)
 
$
(52
)
 
$
(57
)
 
Net income (loss)
18. 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.
19.  Supplemental Cash Flow Information
 
Six Months Ended June 30,
(In millions)
2017
 
2016
Net cash (used in) operating activities:
 
 
 
Interest paid (net of amounts capitalized)
$
(193
)
 
$
(177
)
Income taxes paid to taxing authorities
(43
)
 
(61
)
Noncash investing activities, related to continuing operations:
 

 
 

Asset retirement cost increase
$
12

 
$
2

Asset retirement obligations assumed by buyer
2

 
83

Increase in capital expenditure accrual
183

 
—

Notes receivable for disposal of assets
742

 
—



23
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



20.   Commitments and Contingencies
The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs which we claimed for U.K. corporation tax purposes.  The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In July 2017, a hearing took place at the U.K.’s First-tier Tribunal with respect to this tax deduction.  If 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, 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. 
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 in the prices of our products and services, our operating results will be adversely affected.  We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

24



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
Executive Overview
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.
Executive Overview
We are an independent exploration and production company based in Houston, Texas focused on U.S. unconventional resource plays with operations in the United States, Africa and Europe. Total proved reserves were 1.4 billion boe at December 31, 2016, excluding our Canadian business, and total assets were $24.2 billion at June 30, 2017.
As discussed in Note 6 to the consolidated financial statements, we closed on the sale of our Canadian business, which has been reflected as discontinued operations and is excluded from operations in all periods presented.
Key highlights include the following:
Liquidity and corporate financing
•
At the end of the second quarter 2017, we had $5.9 billion of liquidity, comprised of $2.6 billion in cash and an undrawn $3.3 billion revolving credit facility.
•
In July 2017 we expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion, and in June 2017 we extended the maturity date one year to 2021.
•
In July 2017, we issued $1 billion of 4.4% senior notes due in 2027. Net proceeds plus existing cash on hand will be used in the third quarter to redeem approximately $1.8 billion of 6% senior notes due in 2017, 5.9% senior notes due in 2018 and 7.5% senior notes due in 2019. The offering and redemption will reduce total gross debt by approximately $750 million.
Simplifying our portfolio
•
Closed on the sale of our Canadian business for approximately $2.5 billion with over $1.8 billion in proceeds received to date and $750 million to be received in first quarter 2018.
•
Closed on the Permian basin acquisitions for approximately $1.8 billion with cash on hand.
Financial and Operational results
•
Net sales volumes from continuing operations are 357 mboed, which is 4% higher compared to the same quarter last year; this includes a 7% increase to 202 mboed sales volumes in the U.S. resource plays in our United States E&P segment.
•
Cash provided by operating activities from continuing operations of $923 million for the first six months of 2017, is primarily a result of our average crude oil and condensate price realizations of $47.46 per bbl in the first half of 2017.
•
Our net loss per share from continuing operations was $0.18 in the second quarter of 2017 as compared to a net loss per share of $0.16 in the same period last year. Included in the second quarter 2017 and comparable period net loss are:
◦
An increase in sales and other operating revenues of approximately 40% to $958 million, including a commodity derivative net gain of $56 million compared to a net loss of $88 million in the comparable quarter.
◦
Production expense decreased 5% while sales volumes increased in second quarter 2017 compared to the same quarter last year.
◦
Our provision for income taxes was $41 million in the second quarter of 2017 compared to a benefit of $54 million

25

in the same quarter last year, resulting from Libya tax expense due to resumption of production and no tax benefit due to the full valuation allowance on our federal deferred tax assets in the current quarter.
◦
Exploration expenses decreased primarily as a result of our decision in 2016 not to drill any of our remaining undeveloped Gulf of Mexico leases.
◦
Second quarter 2016 includes a net gain on sale of $294 million primarily relating to the sale of our Wyoming upstream and midstream non-core assets.
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 Volumes
2017
 
2016
 
Increase (Decrease)
 
2017
 
2016
 
Increase
(Decrease)
United States E&P (mboed)
222
 
224
 
(1)%
 
215
 
232
 
(7)%
International E&P (mboed)
135
 
120
 
13%
 
131
 
108
 
21%
Total Continuing Operations (mboed)
357
 
344
 
4%
 
346
 
340
 
2%

United States E&P
Net sales volumes in the segment were marginally lower in second quarter 2017 primarily as a result of the disposition of Wyoming and certain other non-operated assets in West Texas and New Mexico in 2016, which was partially offset by the acquisitions and development in the Oklahoma STACK and Northern Delaware. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Net Sales Volumes (a)
2017
 
2016
 
Increase (Decrease)
 
2017
 
2016
 
Increase
(Decrease)
Equivalent Barrels (mboed)
 
 
 
 
 
 
 
 
 
 
 
Oklahoma Resource Basins
49
 
27
 
81%
 
46
 
27
 
70%
Eagle Ford
100
 
109
 
(8)%
 
100
 
114
 
(12)%
Bakken
49
 
53
 
(8)%
 
48
 
55
 
(13)%
Northern Delaware
4
 
—
 
100%
 
2
 
—
 
100%
Other United States (b)
20
 
35
 
(43)%
 
19
 
36
 
(47)%
Total United States E&P
222
 
224
 
(1)%
 
215
 
232
 
(7)%
(a)  
Our U.S. Resource plays consists of the Oklahoma Resource Basins, Eagle Ford, Bakken and Northern Delaware.     
(b) Three and six months ended June 30, 2017 includes a net sales volume reduction from June 30, 2016 of 21 mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further disposition information.


26

 
 
Three Months Ended June 30, 2017
Sales Mix - U.S. Resource Plays
 
Oklahoma Resource Basins
 
Eagle Ford
 
Bakken
 
Northern Delaware
 
Total
Crude oil and condensate
 
29%
 
59%
 
80%
 
56%
 
56%
Natural gas liquids
 
24%
 
20%
 
12%
 
16%
 
19%
Natural gas
 
47%
 
21%
 
8%
 
28%
 
25%

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
Gross Operated - U.S. Resource Plays
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oklahoma Resource Basins:
 
 
 
 
 
 
 
Wells drilled to total depth
23
 
6
 
38
 
11
Wells brought to sales
20
 
5
 
32
 
8
Eagle Ford:
 
 
 
 
 
 
 
Wells drilled to total depth
53
 
40
 
98
 
98
Wells brought to sales
41
 
30
 
88
 
80
Bakken:
 
 
 
 
 
 
 
Wells drilled to total depth
33
 
—
 
45
 
3
Wells brought to sales
2
 
4
 
6
 
10
Northern Delaware
 
 
 
 
 
 
 
Wells drilled to total depth
2
 
—
 
2
 
—
Wells brought to sales (a)
2
 
—
 
2
 
—
 
(a) Includes one well brought to sales early in the second quarter prior to the closing of the acquisition.
•
Oklahoma Resource Basins – Our net sales volumes in the second quarter increased by more than 80% from the year ago quarter, with net sales volumes of 49 mboed in second quarter 2017. Our second STACK infill spacing pilot, the Hansens pad located in the normally pressured Meramec black oil window east of the Yost pad, tested a tighter well spacing design. Additionally, we also continued delineation and leasehold activity with strong results.
•
Eagle Ford – Our net sales volumes were 100 mboed in the second quarter 2017 which was 8% lower compared to the prior year quarter. We brought 41 gross operated wells to sales in the second quarter compared to 30 in the second quarter 2016. A new Company record was set again for the fastest operated well drilled in the Eagle Ford at a rate of more than 4,200 feet per day.
•
Bakken – Our net sales volumes were 49 mboed compared to 53 mboed in the prior year quarter. In second quarter 2017 we brought two gross operated wells to sales in the Hector with enhanced completion designs.
•
Northern Delaware – Our net sales volumes were 4 net mboed in second quarter 2017, reflecting the May 1 closing of BC Operating assets and June 1 closing of Black Mountain assets. During second quarter 2017 we brought online our first well with a company designed completion in Northern Delaware with successful results, pushing delineation west in Eddy County.
•
Other United States – Net sales volumes declined in second quarter 2017 primarily due to the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for information about dispositions. This decrease was partially offset by the Gunflint field located in Mississippi Canyon block 948 in the Gulf of Mexico which began production in the second half of 2016.


27

International E&P
Net sales volumes were higher in second quarter 2017 compared to second quarter 2016 primarily due to the resumption of sales volumes and production in Libya and increased sales volumes in E.G. resulting from the completion and start-up of the E.G. Alba field compression project in mid-2016. The following table provides details regarding net sales volumes for our significant operations within this segment.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Net Sales Volumes
2017
 
2016
 
Increase (Decrease)
 
2017
 
2016
 
Increase
(Decrease)
Equivalent Barrels (mboed)
 
 
 
 
 
 
 
 
 
 
 
Equatorial Guinea
105
 
101
 
4%
 
104
 
93
 
12%
United Kingdom(a)
18
 
19
 
(5)%
 
14
 
15
 
(7)%
Libya
11
 
—
 
100%
 
12
 
—
 
100%
Other International
1
 
—
 
100%
 
1
 
—
 
100%
Total International E&P
135
 
120
 
13%
 
131
 
108
 
21%
Equity Method Investees
 
 
 
 

 
 
 
 
 
 
LNG (mtd)
6,243
 
5,797
 
8%
 
6,195
 
5,060
 
22%
Methanol (mtd)
1,182
 
1,303
 
(9)%
 
1,244
 
1,292
 
(4)%
Condensate & LPG (boed)
11,608
 
11,306
 
3%
 
13,069
 
10,757
 
21%
(a) 
Includes natural gas acquired for injection and subsequent resale.
•
Equatorial Guinea – Second quarter 2017 net sales were higher compared to the same quarter in 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016.
•
United Kingdom – Net sales volumes in the first six months of 2017 were marginally lower compared to the first six months of 2016 as a result of reliability issues at the outside-operated Foinaven Field.
•
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 second quarter 2017.


28


Market Conditions
Crude oil, natural gas and NGL benchmarks increased in the second quarter and first six months of 2017 as compared to the same period in 2016; as a result, we experienced increased price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
United States E&P
 The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the second quarter and first six months of 2017 and 2016.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
Increase (Decrease)
 
2017
 
2016
 
Increase (Decrease)
Average Price Realizations (a)
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate (per bbl) (b)
$45.81
 
$40.77
 
12%
 
$47.09
 
$34.21
 
38%
Natural Gas Liquids (per bbl)
17.61
 
14.84
 
19%
 
18.46
 
11.43
 
62%
Total Liquid Hydrocarbons (per bbl)
39.00
 
35.07
 
11%
 
40.04
 
29.32
 
37%
Natural Gas (per mcf) (c)
3.05
 
1.96
 
56%
 
3.03
 
1.99
 
52%
Benchmarks
 
 
 
 
 
 
 
 
 
 
 
WTI crude oil (per bbl)
$48.15
 
$45.64
 
5%
 
$49.95
 
$39.78
 
26%
LLS crude oil (per bbl)
50.18
 
47.35
 
6%
 
51.77
 
41.49
 
25%
Mont Belvieu NGLs (per bbl) (d)
20.99
 
17.52
 
20%
 
21.95
 
15.78
 
39%
Henry Hub natural gas (per mmbtu)
3.18
 
1.95
 
63%
 
3.25
 
2.02
 
61%
(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 $1.07 per bbl and $0.12 per bbl for the second quarter 2017 and 2016, and $0.72 per bbl and $0.91 per bbl for the first six 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.
Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.
Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.
Natural gas – A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  
International E&P
The following table presents our average price realizations and the related benchmark for crude oil for the second quarter and first six months of 2017 and 2016.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
Increase (Decrease)
 
2017
 
2016
 
Increase
(Decrease)
Average Price Realizations
 
 
 
 
 
 
 
 
 
 
 
Crude Oil and Condensate (per bbl)
$47.04
 
$42.21
 
11%
 
$48.58
 
$37.56
 
29%
Natural Gas Liquids (per bbl)
1.77
 
2.65
 
(33)%
 
2.83
 
2.45
 
16%
Liquid Hydrocarbons (per bbl)
37.11
 
32.11
 
16%
 
37.83
 
28.11
 
35%
Natural Gas (per mcf)
0.57
 
0.53
 
8%
 
0.56
 
0.56
 
—%
Benchmark
 
 
 
 

 
 
 
 
 

Brent (Europe) crude oil (per bbl) (a)
$49.67
 
$45.52
 
9%
 
$51.68
 
$39.61
 
30%
(a) 
Average of monthly prices obtained from EIA website.

29


Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba Plant. The Alba Plant 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 are sold by Alba Plant at market prices, with our share of its income/loss reflected in Income from equity method investments, and the dry natural gas from Alba Plant is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and natural gas will not fully track market price movements. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings 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, which are sold at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the Consolidated Statements of Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.
Results of Operations
Three Months Ended June 30, 2017 vs. Three Months Ended June 30, 2016
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Three Months Ended June 30,
(In millions)
2017
 
2016
Sales and other operating revenues, including related party
 
 
 
United States E&P
$
695

 
$
617

International E&P
220

 
159

Segment sales and other operating revenues, including related party
$
915

 
$
776

Unrealized gain (loss) on commodity derivative instruments
43

 
(91
)
Sales and other operating revenues, including related party
$
958

 
$
685

Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
 
 
Three Months Ended
 
Increase (Decrease) Related to
 
Three Months Ended
(In millions)
 
June 30, 2016
 
Price Realizations
 
Net Sales Volumes
 
June 30, 2017
United States E&P Price-Volume Analysis (a)
Liquid hydrocarbons
 
$
551

 
$
59

 
$
(22
)
 
$
588

Natural gas
 
55

 
34

 
5

 
94

Realized gain on commodity
 
 
 
 
 
 
 
 
    derivative instruments
 
3

 


 


 
13

Other sales
 
8

 


 


 
—

Total
 
$
617

 
 
 
 
 
$
695

International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
129

 
$
25

 
$
33

 
$
187

Natural gas
 
22

 
2

 
1

 
25

Other sales
 
8

 
 
 
 
 
8

Total
 
$
159

 
 
 
 
 
$
220

(a)  
Three months ended June 30, 2017 includes a net sales volume reduction from June 30, 2016 of 21 mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further information.
Marketing revenues decreased $41 million in the second quarter of 2017 from 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 based 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.
Income from equity method investments increased $14 million in the second quarter of 2017 from the comparable 2016 period. The improvement is primarily due to higher price realizations from methanol at our AMPCO methanol facility.

30


Net gain on disposal of assets decreased $288 million in the second quarter of 2017 primarily related to the gain on sale of our Wyoming upstream and midstream non-core assets in the second quarter of 2016. See Note 6 to the consolidated financial statements for further information.
Production expenses decreased $9 million in the second quarter of 2017 versus the same period in 2016. United States E&P declined $11 million primarily due to the disposition of our non-core assets in Wyoming during the second half of 2016 partially offset by our Gunflint field beginning production in the second half of 2016 and the acquisitions of our Oklahoma STACK and Northern Delaware assets. International E&P increased $2 million primarily in Libya during the second quarter of 2017.
The second quarter of 2017 production expense rate (expense per boe) for United States E&P was lower as costs declined, primarily due to dispositions, as sales volumes were marginally lower. The expense rate for International E&P declined due to an increase in sales volumes in E.G. and Libya.
The following table provides production expense rates for each segment:
 
Three Months Ended June 30,
($ per boe)
2017
 
2016
Production Expense Rate
 
 
 
United States E&P

$5.86

 

$6.28

International E&P

$4.68

 

$5.09

Marketing costs decreased $37 million in the second quarter of 2017 from the comparable 2016 period, consistent with the marketing revenues changes discussed above.
Other operating expenses increased $24 million in the second quarter of 2017 primarily as a result of an increase in shipping and handling costs due to rate increases in Bakken and Oklahoma. Additionally, increased sales volumes in Oklahoma due to the Oklahoma STACK acquisition in the second half of 2016 attributed to the increase.
Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $152 million in the second quarter of 2017 primarily as a result of our decision in 2016 not to drill any of our remaining Gulf of Mexico undeveloped leases. The following table summarizes the components of exploration expenses:
 
Three Months Ended June 30,
(In millions)
2017
 
2016
Exploration Expenses
 
 
 
Unproved property impairments
$
25

 
$
133

Dry well costs
—

 
15

Geological and geophysical
—

 
—

Other
5

 
34

Total exploration expenses
$
30

 
$
182

Depreciation, depletion and amortization increased $80 million in the second quarter of 2017 primarily as a result of an increase of $62 million in the United States E&P due to our Gunflint field beginning production in the second half of 2016 and sales volumes from the acquisitions and development in the Oklahoma STACK and Northern Delaware. Also contributing to this higher expense was an increase of $21 million in our International E&P segment resulting from higher sales volumes in E.G. due to the completion and start-up of our Alba field compression project in mid-2016, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. 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 changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. Our United States E&P DD&A rate increased in the second quarter of 2017 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. The DD&A rate for International E&P increased 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. The following table provides DD&A rates for each segment.

31


 
Three Months Ended June 30,
($ per boe)
2017
 
2016
DD&A Rate
 
 
 
United States E&P

$24.49

 

$21.16

International E&P

$7.23

 

$6.22

Taxes other than income include production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $10 million in the second quarter of 2017 versus the same period in 2016. The increase in the second quarter 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:
 
Three Months Ended June 30,
(In millions)
2017
 
2016
Production and severance
$
23

 
$
25

Ad valorem
1

 
5

Other
21

 
5

Total
$
45

 
$
35

General and administrative expenses decreased $38 million primarily due to a decrease in pension settlement charges related to workforce reductions which were reduced in the second quarter of 2017 to $3 million compared to $31 million for the same period in 2016.
Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 37% in the second quarter of 2017, as compared to a benefit of 28% in the second quarter of 2016. We placed a full valuation allowance on our federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for more detail 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 excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
 
Three Months Ended June 30,
(In millions)
2017
 
2016
United States E&P
$
(107
)
 
$
(70
)
International E&P
59

 
55

Segment income (loss)
(48
)
 
(15
)
Items not allocated to segments, net of income taxes
(105
)
 
(123
)
Income (loss) from continuing operations
(153
)
 
(138
)
Income (loss) from discontinued operations (a)
14

 
(32
)
Net income (loss)
$
(139
)
 
$
(170
)
(a) We entered into an agreement to sell our Canadian business in the first quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
 United States E&P segment loss increased $37 million after-tax in the second quarter of 2017 primarily due to a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period and an increase in DD&A expenses due to the completion of projects and acquisitions. This was partially offset by higher price realizations and lower production costs due to non-core asset dispositions.
International E&P segment income increased $4 million after-tax in the second quarter of 2017 primarily due to higher price realizations and an increase in sales volumes in E.G. and Libya and an increase in income from equity investments. This was nearly completely offset by an increase in DD&A and income tax expenses.

32


Results of Operations
Six Months Ended June 30, 2017 vs. Six Months Ended June 30, 2016
Consolidated Results of Operation
Sales and other operating revenues, including related party are presented by segment in the table below:
 
Six Months Ended June 30,
(In millions)
2017
 
2016
Sales and other operating revenues, including related party
 
 
 
United States E&P
$
1,369

 
$
1,110

International E&P
423

 
255

Segment sales and other operating revenues, including related party
$
1,792

 
$
1,365

Unrealized gain (loss) on commodity derivative instruments
120

 
(114
)
Sales and other operating revenues, including related party
$
1,912

 
$
1,251

 
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.

 
 
Six Months Ended
 
Increase (Decrease) Related to
 
Six Months Ended
(In millions)
 
June 30, 2016
 
Price Realizations
 
Net Sales Volumes
 
June 30, 2017
United States E&P Price-Volume Analysis (a)
Liquid hydrocarbons
 
$
960

 
$
313

 
$
(101
)
 
$
1,172

Natural gas
 
113

 
61

 
3

 
177

Realized gain on commodity
 
 
 
 
 
 
 
 
    derivative instruments
 
24

 


 
 
 
17

Other sales
 
13

 
 
 
 
 
3

Total
 
$
1,110

 
 
 
 
 
$
1,369

International E&P Price-Volume Analysis
Liquid hydrocarbons
 
$
194

 
$
92

 
$
73

 
$
359

Natural gas
 
43

 
—

 
5

 
48

Other sales
 
18

 
 
 
 
 
16

Total
 
$
255

 
 
 
 
 
$
423

(a)      Six months ending June 30, 2017 includes a net sales volume reduction from June 30, 2016 of 21 mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further information.
Marketing revenues for the first six months of 2017 decreased by $53 million. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decrease is related primarily to lower marketed volumes in the United States E&P segment due to non-core asset dispositions.
Income from equity method investments increased $69 million for the first six months of 2017 primarily due to higher price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement in net sales volumes primarily driven by the completion of the Alba field compression project in E.G. during the second half of 2016.
Net gain (loss) on disposal of assets decreased $227 million for the first six months of 2017. This decrease was primarily related to the sale of non-core assets in the first half of 2016 in Wyoming, West Texas and New Mexico, and the Gulf of Mexico. See Note 6 to the consolidated financial statements for information about dispositions.
Production expenses for the first six months of 2017 decreased by $45 million compared to the same period in 2016. United States E&P declined $36 million primarily due to the disposition of our non-core assets in Wyoming during the second half of 2016 partially offset by our Gunflint field beginning production in the second half of 2016 and the acquisitions of our Oklahoma STACK and Northern Delaware assets. International E&P declined $9 million primarily as a result of lower planned maintenance costs in the first six months of 2017 in E.G. compared to the same period in 2016.

33


The first six months of 2017 production expense rate (expense per boe) for United States E&P was lower as costs declined, primarily due to dispositions, and as sales volumes were marginally lower. The International E&P expense rate decreased in the first six months of 2017 primarily due to an increase in sales volumes in E.G. and Libya, combined with lower planned maintenance costs in E.G. due to planned maintenance in the first half of 2016.
 
Six Months Ended June 30,
($ per boe)
2017
 
2016
Production Expense Rate
 
 
 
United States E&P

$5.82

 

$6.22

International E&P

$4.22

 

$5.53

Marketing costs decreased $49 million in the first six months of 2017 from the comparable 2016 period, consistent with the marketing revenues changes discussed above.
Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $148 million in the first six months of 2017 versus the comparable 2016 period. Unproved property impairments decreased primarily as a result of our decision in 2016 not to drill any of our remaining Gulf of Mexico undeveloped leases. The following table summarizes the components of exploration expenses:
 
Six Months Ended June 30,
(In millions)
2017
 
2016
Exploration Expenses
 
 
 
Unproved property impairments
$
45

 
$
144

Dry well costs
—

 
15

Geological and geophysical
1

 
—

Other
12

 
47

Total exploration expenses
$
58

 
$
206

Depreciation, depletion and amortization increased $87 million in the first six months of 2017 from the comparable 2016 period primarily as a result of an increase of $47 million in the United States E&P due to our Gunflint field beginning production in the second half of 2016 and sales volumes from the acquisitions and development in the Oklahoma STACK and Northern Delaware. Also contributing to this higher expense was an increase of $46 million in our International E&P segment resulting from higher sales volumes in E.G. due to the completion and start-up of our Alba field compression project in mid-2016, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. 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 sales volumes, reserves and capitalized costs, can also cause changes to 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. The DD&A rate for International E&P increased 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. The following table provides DD&A rates for each segment.
 
Six Months Ended June 30,
($ per boe)
2017
 
2016
DD&A Rate
 

 
 

United States E&P

$24.81

 

$21.79

International E&P

$6.93

 

$5.98


34


Taxes other than income include production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $6 million in the first six months of 2017 from the comparable 2016 period. The increase in the first six 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:
 
Six Months Ended June 30,
(In millions)
2017
 
2016
Production and severance
$
48

 
$
44

Ad valorem
4

 
19

Other
32

 
15

Total
$
84

 
$
78

General and administrative expenses decreased $80 million in the first six months of 2017 compared to the same period in 2016. This decrease was primarily due to a decrease in pension settlement charges related to workforce reductions which were reduced in the first six months of 2017 to $17 million compared to $79 million for the same period in 2016.
Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 59% in the first six months of 2017, as compared to a benefit of 38% from the comparable 2016 period. We placed a full valuation allowance on our federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any 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.
Segment Income (Loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
 
Six Months Ended June 30,
(In millions)
2017
 
2016
United States E&P
$
(186
)
 
$
(265
)
International E&P
152

 
59

Segment income (loss)
(34
)
 
(206
)
Items not allocated to segments, net of income taxes
(169
)
 
(292
)
Income (loss) from continuing operations
(203
)
 
(498
)
Income (loss) from discontinued operations (a)
(4,893
)
 
(79
)
Net income (loss)
$
(5,096
)
 
$
(577
)
(a) We entered into an agreement to sell our Canadian business in the first quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.
 United States E&P segment loss decreased $79 million after-tax in the first six months of 2017 from the comparable 2016 period primarily due to higher price realizations and lower production costs as a result of dispositions and lower sales volumes. This was partially offset by a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period, an increase in DD&A expenses due to the completion of projects and a decrease in our sales volumes primarily due to dispositions.
International E&P segment income increased $93 million after-tax in the first six months of 2017 from the comparable 2016 period primarily due to higher price realizations and an increase in sales volumes in E.G. and Libya, and an increase in income from equity investments. This was partially offset by an increase in DD&A and income tax expenses.

35


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, except as discussed below.
Fair Value Estimates - Goodwill
Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level, as of June 30, 2017 we have $115 million of goodwill associated with our International E&P reporting unit. We performed our annual impairment test in April 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%. See Note 13 to the consolidated financial statements for further information.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
 
Six Months Ended June 30,
(In millions)
2017
 
2016
Sources of cash and cash equivalents
 

 
 

Operating activities - continuing operations
$
923

 
$
267

Disposals of assets
1,726

 
758

Common stock issuance
—

 
1,236

Other
49

 
39

Total sources of cash and cash equivalents
$
2,698

 
$
2,300

Uses of cash and cash equivalents
 
 
 
Cash additions to property, plant and equipment
$
(775
)
 
$
(728
)
Acquisitions, net of cash acquired
(1,828
)
 
—

Deposits for acquisitions
—

 
(89
)
Dividends paid
(85
)
 
(77
)
Purchases of common stock
(10
)
 
(4
)
Other
(6
)
 
—

Total uses of cash and cash equivalents
$
(2,704
)
 
$
(898
)
Cash flows generated from operating activities in the first six months of 2017 was higher as commodity prices improved compared to the first six months of 2016. This drove an increase in price realizations in the first six months of 2017. Consolidated average liquid hydrocarbon price realizations increased by more than 35% during the first six months of 2017 as compared to the prior period. This increase in price realization coupled with our continued focus on cost reduction, including production expense and general & administrative expense, resulted in our increased cash flows generated from operating activities.
Proceeds from the disposals of assets for the first six months of 2017 are from the disposal of our Canadian business; see Note 6 to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See Note 18 to the consolidated financial statements for additional information.

36


Additions to property, plant and equipment in the first six 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:
 
Six Months Ended June 30,
(In millions)
2017
 
2016
United States E&P
$
924

 
$
468

International E&P
23

 
44

Corporate
11

 
8

Total capital expenditures
958

 
520

Decrease (increase) in capital expenditure accrual
(183
)
 
208

Total use of cash and cash equivalents for property, plant and equipment
$
775

 
$
728

In the second quarter of 2017 we closed on our acquisition of the Northern Delaware assets for a purchase price of $1.8 billion, subject to closing adjustments. See Note 5 to the consolidated financial statements for additional information.
The Board of Directors approved a $0.05 per share dividend for the first quarter of 2017, which was paid in the second quarter of 2017. See Capital Requirements below for additional information about the second quarter dividend.
Liquidity and Capital Resources
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 notes is payable semi-annually beginning January 15, 2018. We will use the net proceeds plus existing cash on hand to redeem the following senior 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

The new issuance together with the redemption will result in a reduction in total gross debt of approximately $750 million in the third quarter of 2017. In July 2017, we gave notice that we will redeem during the third quarter of 2017, $1.76 billion of the senior unsecured notes discussed above in accordance with their make-whole call provisions. As a result of this notice we expect to recognize into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017. See Note 14 for detail relating to the proceeds of $54 million, which will result in a gain of approximately $47 million into earnings in the third quarter of 2017, on the termination of our forward starting interest rate swaps associated with this issuance.
In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021, and maintained the Credit Facility at $3.3 billion. 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. 
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. At June 30, 2017, we had approximately $5.9 billion of liquidity consisting of $2.6 billion in cash and cash equivalents and $3.3 billion available under our revolving credit facility. Our working capital requirements are supported by these sources and we may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management 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 could affect our operations and our ability to access the capital markets. Our corporate credit ratings as of June 30, 2017 are: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (negative); and Moody's Investor Services, Inc. Ba1 (stable). A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016 for a discussion of how a further downgrade in our credit ratings could affect us.

37


Capital Resources
Credit Arrangements and Borrowings
At June 30, 2017, we had no borrowings against our revolving credit facility.
At June 30, 2017, we had $7.3 billion in long-term debt outstanding. As a result of the debt issuance discussed above, we reclassified $990 million of the 6.0% senior notes due in 2017 and 5.9% senior notes due in 2018 to long-term debt as we have the intent and ability to redeem them with the net proceeds received from the debt issuance. Therefore, as of June 30, 2017, we had long-term debt due within one year of $548 million.
We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. 
Asset Disposal
In the second quarter of 2017 we closed on the sale of our Canadian business for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds of $750 million will be paid to us in the first quarter of 2018. See Note 6 to the consolidated financial statements for additional information.
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 27% at June 30, 2017, compared to 21% at December 31, 2016.
 
June 30,
 
December 31,
(In millions)
2017
 
2016
Long-term debt due within one year
$
548

 
$
686

Long-term debt
6,715

 
6,581

Total debt
$
7,263

 
$
7,267

Cash and cash equivalents
$
2,614

 
$
2,488

Equity
$
12,405

 
$
17,541

Calculation:
 

 
 

Total debt
$
7,263

 
$
7,267

Minus cash and cash equivalents
2,614

 
2,488

Total debt minus cash, cash equivalents
$
4,649

 
$
4,779

Total debt
$
7,263

 
$
7,267

Plus equity
12,405

 
17,541

Minus cash and cash equivalents
2,614

 
2,488

Total debt plus equity minus cash, cash equivalents
$
17,054

 
$
22,320

Cash-adjusted debt-to-capital ratio
27
%
 
21
%
Capital Requirements
Capital Spending
As a result of strong operational performance in the first half of the year and continued efficiency gains we expect our Capital Program for full-year 2017 to decrease from $2.4 billion to a range of $2.1 to $2.2 billion.
Other Expected Cash Outflows
On July 26, 2017, our Board of Directors approved a dividend of $0.05 per share for the second quarter of 2017 payable September 11, 2017 to stockholders of record at the close of business on August 16, 2017.
As of June 30, 2017, we plan to make contributions of up to $33 million to our funded pension plans during the remainder of 2017.
In July 2017, we gave notice that we will redeem during the third quarter of 2017, $1.76 billion of the senior unsecured notes discussed above in accordance with their make-whole call provisions. As a result of this notice we expect to recognize

38


into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017.
Contractual Cash Obligations
As of June 30, 2017, there are no material changes to 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. See Note 6 to the consolidated financial statements for additional information. As a result, as of June 30, 2017, our consolidated contractual cash obligations from our continuing operations has decreased by $1,239 million from December 31, 2016 primarily due to obligations relating to the sale of our Canadian business. Our purchase obligations under oil and gas activities decreased by $45 million, service and materials contracts decreased $646 million and transportation and related contracts decreased $270 million when comparing June 30, 2017 to December 31, 2016.

Environmental Matters and Other Contingencies
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 that will be reduced under the terms by mitigating corrective actions.  We 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. 
See Note 20 to the consolidated financial statements for a description of other contingencies.
Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical fact, including without limitation statements regarding our future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, cost and expense estimates, asset acquisitions and dispositions, future financial position, future payments for our Canadian disposition and other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend," “may,” “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, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
•
risks related to our hedging activities;
•
capital available for exploration and development;
•
the inability of any party to satisfy closing conditions with respect to our asset disposition;
•
drilling and operating risks;
•
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 contractual obligations;
•
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
•
cyber-attacks;
•
changes in safety, health, environmental, tax and other regulations;
•
other geological, operating and economic considerations; and
•
the risk factors, forward-looking statements and challenges and uncertainties described in our 2016 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.

39


Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2016 Annual Report on Form 10-K. Notes 13 and 14 to the consolidated financial statements include additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.
Commodity Price Risk During the first six months of 2017, we entered into 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. The following tables provide a summary of open positions as of June 30, 2017 and the weighted average price for those contracts:
Crude Oil
 
2017
2018
 
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
Three-Way Collars (a)
 
 
 
 
Volume (Bbls/day)
50,000
50,000
20,000
20,000
Weighted average price per Bbl:
 
 
 
 
Ceiling
$60.37
$60.37
$57.86
$57.86
Floor
$54.80
$54.80
$53.00
$53.00
Sold put
$47.80
$47.80
$47.00
$47.00
Sold call options (b)
 
 
 
 
Volume (Bbls/day)
35,000
35,000
—
—
Weighted average price per Bbl
$61.91
$61.91
—
—
(a) 
Subsequent to June 30, 2017, we entered into 20,000 Bbls/day of three-way collars for January - December 2018 with an average ceiling price of $55.09, a floor price of $50.00, and a sold put price of $43.00.
(b) 
Call options settle monthly.
Natural Gas
 
2017
2018
 
Third Quarter
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Three-Way Collars
 
 
 
 
 
 
Volume (MMBtu/day)
120,000
120,000
200,000
160,000
160,000
160,000
Weighted average price per MMBtu:
 
 
 
 
 
 
Ceiling
$3.58
$3.71
$3.79
$3.61
$3.61
$3.61
Floor
$3.09
$3.14
$3.08
$3.00
$3.00
$3.00
Sold put
$2.55
$2.60
$2.55
$2.50
$2.50
$2.50
Swaps
 
 
 
 
 
 
Volume (MMBtu/day)
20,000
20,000
—
—
—
—
Weighted average price per MMBtu
$2.93
$2.93
—
—
—
—

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of June 30, 2017.
(In millions)
Hypothetical Price Increase of 10%
Hypothetical Price Decrease of 10%
 
 
 
Crude oil derivatives
$
(30
)
$
18

Natural gas derivatives
(15
)
13

Total
$
(45
)
$
31



40


Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10% decrease in interest rates on financial assets and liabilities as of June 30, 2017, is provided in the following table.
(In millions)
Fair Value
 
Incremental Change in Fair Value
Financial assets (liabilities): (a)
 
 
 
Interest rate fair value hedges
$
1

(b) 
$
1

Interest rate swaps
$
53

(b) 
$
(15
)
Long term debt, including amounts due within one year
$
(7,451
)
(b)(c) 
$
(254
)
(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 June 30, 2017.  
During the first six months of 2017, 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.

41


Part II – OTHER INFORMATION
Item 1. Legal Proceedings
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.  
See Note 20 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 June 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 that will be reduced under the terms by mitigating corrective actions.  We 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.  There have been no material changes to the risk factors under Item 1A. Risk Factors in our 2016 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about repurchases by Marathon Oil of its common stock during the quarter ended June 30, 2017.
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)
04/01/17 - 04/30/17
66,785

 
$16.23
 
—

 
$
1,500,285,529

05/01/17 - 05/31/17
123,405

 
$14.83
 
—

 
$
1,500,285,529

06/01/17 - 06/30/17
493

 
$13.18
 
—

 
$
1,500,285,529

Total
190,683

 
$15.32
 
—

 
 
(a) 
190,683 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 June 30, 2017 is $1.5 billion. No repurchases were made under the program in the second 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.

42


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.
August 3, 2017
 
MARATHON OIL CORPORATION
 
 
 
 
By:
/s/ Gary E. Wilson
 
 
Gary E. Wilson
 
 
Vice President, Controller and Chief Accounting Officer
 
 
(Duly Authorized Officer)

43


Exhibit Index
 
 
 
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number
 
Exhibit Description
Form
 
Exhibit
 
Filing Date
 
3.1
 
10-Q
 
3.1
 
8/8/2013
 
3.2
 
8-K
 
3.1
 
3/1/2016
 
3.3
 
10-K
 
3.3
 
2/28/2014
 
4.1
 
10-K
 
4.2
 
2/28/2014
 
10.1
 
8-K
 
99.1
 
6/23/2017
 
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.
 
 
 
 
 
 
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.