UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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(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, 20152016 |
OR
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[ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from _____ to _____ |
Commission file number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
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Delaware | | 25-0996816 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
5555 San Felipe Street, Houston, TX 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer þ | Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
There were 677,184,913847,258,512 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2015.2016.
MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2015 Annual Report on Form 10-K.
Part I - Financial Information
Item 1. Financial Statements
MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
| | | Three Months Ended | | Six Months Ended | Three Months Ended | | Six Months Ended |
| June 30, | | June 30, | June 30, | | June 30, |
(In millions, except per share data) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
Revenues and other income: | | | | | | | | | | | | | | |
Sales and other operating revenues, including related party | $ | 1,307 |
| | $ | 2,270 |
| | $ | 2,587 |
| | $ | 4,419 |
| $ | 870 |
| | $ | 1,307 |
| | $ | 1,584 |
| | $ | 2,587 |
|
Marketing revenues | 183 |
| | 618 |
| | 387 |
| | 1,159 |
| 89 |
| | 183 |
| | 147 |
| | 387 |
|
Income from equity method investments | 26 |
| | 120 |
| | 62 |
| | 257 |
| 37 |
| | 26 |
| | 51 |
| | 62 |
|
Net gain (loss) on disposal of assets | — |
| | (87 | ) | | 1 |
| | (85 | ) | 294 |
| | — |
| | 234 |
| | 1 |
|
Other income | 15 |
| | 20 |
| | 26 |
| | 40 |
| 12 |
| | 15 |
| | 16 |
| | 26 |
|
Total revenues and other income | 1,531 |
| | 2,941 |
| | 3,063 |
| | 5,790 |
| 1,302 |
| | 1,531 |
| | 2,032 |
| | 3,063 |
|
Costs and expenses: | |
| | |
| | | | |
| |
| | |
| | | | |
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Production | 450 |
| | 562 |
| | 894 |
| | 1,104 |
| 350 |
| | 450 |
| | 678 |
| | 894 |
|
Marketing, including purchases from related parties | 182 |
| | 614 |
| | 387 |
| | 1,156 |
| 88 |
| | 182 |
| | 146 |
| | 387 |
|
Other operating | 81 |
| | 101 |
| | 188 |
| | 204 |
| 95 |
| | 81 |
| | 204 |
| | 188 |
|
Exploration | 111 |
| | 145 |
| | 201 |
| | 218 |
| 189 |
| | 111 |
| | 213 |
| | 201 |
|
Depreciation, depletion and amortization | 751 |
| | 680 |
| | 1,572 |
| | 1,323 |
| 561 |
| | 751 |
| | 1,170 |
| | 1,572 |
|
Impairments | 44 |
| | 4 |
| | 44 |
| | 21 |
| — |
| | 44 |
| | 1 |
| | 44 |
|
Taxes other than income | 78 |
| | 109 |
| | 145 |
| | 204 |
| 39 |
| | 78 |
| | 87 |
| | 145 |
|
General and administrative | 168 |
| | 139 |
| | 339 |
| | 326 |
| 132 |
| | 168 |
| | 283 |
| | 339 |
|
Total costs and expenses | 1,865 |
| | 2,354 |
| | 3,770 |
| | 4,556 |
| 1,454 |
| | 1,865 |
| | 2,782 |
| | 3,770 |
|
Income (loss) from operations | (334 | ) | | 587 |
| | (707 | ) | | 1,234 |
| (152 | ) | | (334 | ) | | (750 | ) | | (707 | ) |
Net interest and other | (58 | ) | | (76 | ) | | (105 | ) | | (125 | ) | (86 | ) | | (58 | ) | | (171 | ) | | (105 | ) |
Income (loss) from continuing operations before income taxes | (392 | ) | | 511 |
| | (812 | ) | | 1,109 |
| |
Income (loss) before income taxes | | (238 | ) | | (392 | ) | | (921 | ) | | (812 | ) |
Provision (benefit) for income taxes | (6 | ) | | 151 |
| | (150 | ) | | 351 |
| (68 | ) | | (6 | ) | | (344 | ) | | (150 | ) |
Income (loss) from continuing operations | (386 | ) | | 360 |
| | (662 | ) | | 758 |
| |
Discontinued operations | — |
| | 180 |
| | — |
| | 931 |
| |
Net income (loss) | $ | (386 | ) | | $ | 540 |
| | $ | (662 | ) | | $ | 1,689 |
| $ | (170 | ) | | $ | (386 | ) | | $ | (577 | ) | | $ | (662 | ) |
Per basic share: | |
| | |
| | |
| | |
| |
Income (loss) from continuing operations | $ | (0.57 | ) | | $ | 0.53 |
| | $ | (0.98 | ) | | $ | 1.11 |
| |
Discontinued operations | $ | — |
| | $ | 0.27 |
| | $ | — |
| | $ | 1.36 |
| |
Net income (loss) | $ | (0.57 | ) | | $ | 0.80 |
| | $ | (0.98 | ) | | $ | 2.47 |
| |
Per diluted share: | | | | | | | | |
Income (loss) from continuing operations | $ | (0.57 | ) | | $ | 0.53 |
| | $ | (0.98 | ) | | $ | 1.10 |
| |
Discontinued operations | $ | — |
| | $ | 0.27 |
| | $ | — |
| | $ | 1.36 |
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Net income (loss) | $ | (0.57 | ) | | $ | 0.80 |
| | $ | (0.98 | ) | | $ | 2.46 |
| |
Net income (loss) per share: | | |
| | |
| | |
| | |
|
Basic | | $ | (0.20 | ) | | $ | (0.57 | ) | | $ | (0.73 | ) | | $ | (0.98 | ) |
Diluted | | $ | (0.20 | ) | | $ | (0.57 | ) | | $ | (0.73 | ) | | $ | (0.98 | ) |
Dividends per share | $ | 0.21 |
| | $ | 0.19 |
| | $ | 0.42 |
| | $ | 0.38 |
| $ | 0.05 |
| | $ | 0.21 |
| | $ | 0.10 |
| | $ | 0.42 |
|
Weighted average common shares outstanding: | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
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Basic | 677 |
| | 676 |
| | 676 |
| | 684 |
| 848 |
| | 677 |
| | 790 |
| | 676 |
|
Diluted | 677 |
| | 679 |
| | 676 |
| | 688 |
| 848 |
| | 677 |
| | 790 |
| | 676 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
| | | Three Months Ended | | Six Months Ended | Three Months Ended | | Six Months Ended |
| June 30, | | June 30, | June 30, | | June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
Net income (loss) | $ | (386 | ) | | $ | 540 |
| | $ | (662 | ) | | $ | 1,689 |
| $ | (170 | ) | | $ | (386 | ) | | $ | (577 | ) | | $ | (662 | ) |
Other comprehensive income (loss) | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
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Postretirement and postemployment plans | |
| | |
| | |
| | |
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| | |
| | |
| | |
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Change in actuarial loss and other | 86 |
| | (13 | ) | | 162 |
| | (43 | ) | 19 |
| | 86 |
| | (5 | ) | | 162 |
|
Income tax benefit (provision) | (30 | ) | | 5 |
| | (57 | ) | | 15 |
| |
Income tax provision (benefit) | | (7 | ) | | (30 | ) | | 2 |
| | (57 | ) |
Postretirement and postemployment plans, net of tax | 56 |
| | (8 | ) | | 105 |
| | (28 | ) | 12 |
| | 56 |
| | (3 | ) | | 105 |
|
Other, net of tax | | (2 | ) | | — |
| | (2 | ) | | — |
|
Other comprehensive income (loss) | | 10 |
| | 56 |
| | (5 | ) | | 105 |
|
Comprehensive income (loss) | $ | (330 | ) | | $ | 532 |
| | $ | (557 | ) | | $ | 1,661 |
| $ | (160 | ) |
| $ | (330 | ) |
| $ | (582 | ) |
| $ | (557 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
| | | June 30, | | December 31, | June 30, | | December 31, |
(In millions, except per share data) | 2015 | | 2014 | 2016 | | 2015 |
Assets | | | | | | |
Current assets: | | | | | | |
Cash and cash equivalents | $ | 1,572 |
| | $ | 2,398 |
| $ | 2,584 |
| | $ | 1,221 |
|
Short-term investments | 925 |
| | — |
| |
Receivables, less reserve of $4 and $3 | 1,195 |
| | 1,729 |
| |
Receivables, less reserve of $4 and $4 | | 822 |
| | 912 |
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Inventories | 336 |
| | 357 |
| 272 |
| | 313 |
|
Other current assets | 102 |
| | 109 |
| 76 |
| | 144 |
|
Total current assets | 4,130 |
| | 4,593 |
| 3,754 |
| | 2,590 |
|
Equity method investments | 1,045 |
| | 1,113 |
| 944 |
| | 1,003 |
|
Property, plant and equipment, less accumulated depreciation, | |
| | |
| |
| | |
|
depletion and amortization of $23,395 and $21,884 | 29,121 |
| | 29,040 |
| |
depletion and amortization of $21,659 and $23,260 | | 25,657 |
| | 27,061 |
|
Goodwill | 459 |
| | 459 |
| 115 |
| | 115 |
|
Other noncurrent assets | 1,015 |
| | 806 |
| 2,057 |
| | 1,542 |
|
Total assets | $ | 35,770 |
| | $ | 36,011 |
| $ | 32,527 |
| | $ | 32,311 |
|
Liabilities | |
| | |
| |
| | |
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Current liabilities: | |
| | |
| |
| | |
|
Accounts payable | $ | 1,507 |
| | $ | 2,545 |
| $ | 953 |
| | $ | 1,313 |
|
Payroll and benefits payable | 119 |
| | 191 |
| 114 |
| | 133 |
|
Accrued taxes | 156 |
| | 285 |
| 85 |
| | 132 |
|
Other current liabilities | 235 |
| | 290 |
| 229 |
| | 150 |
|
Long-term debt due within one year | 1,035 |
| | 1,068 |
| 1 |
| | 1 |
|
Total current liabilities | 3,052 |
| | 4,379 |
| 1,382 |
| | 1,729 |
|
Long-term debt | 7,321 |
| | 5,323 |
| 7,280 |
| | 7,276 |
|
Deferred tax liabilities | 2,531 |
| | 2,486 |
| 2,392 |
| | 2,441 |
|
Defined benefit postretirement plan obligations | 438 |
| | 598 |
| 409 |
| | 403 |
|
Asset retirement obligations | 1,963 |
| | 1,917 |
| 1,597 |
| | 1,601 |
|
Deferred credits and other liabilities | 247 |
| | 288 |
| 314 |
| | 308 |
|
Total liabilities | 15,552 |
| | 14,991 |
| 13,374 |
| | 13,758 |
|
Commitments and contingencies |
|
| |
|
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| |
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Stockholders’ Equity | |
| | |
| |
| | |
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Preferred stock – no shares issued or outstanding (no par value, | | | | | | |
26 million shares authorized) | — |
| | — |
| — |
| | — |
|
Common stock: | |
| | |
| |
| | |
|
Issued – 770 million shares (par value $1 per share, | | | | |
Issued – 937 million shares and 770 million shares (par value $1 per share, | | | | |
1.1 billion shares authorized) | 770 |
| | 770 |
| 937 |
| | 770 |
|
Securities exchangeable into common stock – no shares issued or | |
| | |
| |
| | |
|
outstanding (no par value, 29 million shares authorized) | — |
| | — |
| — |
| | — |
|
Held in treasury, at cost – 93 million and 95 million shares | (3,555 | ) | | (3,642 | ) | |
Held in treasury, at cost – 89 million and 93 million shares | | (3,397 | ) | | (3,554 | ) |
Additional paid-in capital | 6,484 |
| | 6,531 |
| 7,433 |
| | 6,498 |
|
Retained earnings | 16,691 |
| | 17,638 |
| 14,320 |
| | 14,974 |
|
Accumulated other comprehensive loss | (172 | ) | | (277 | ) | (140 | ) | | (135 | ) |
Total stockholders' equity | 20,218 |
| | 21,020 |
| 19,153 |
| | 18,553 |
|
Total liabilities and stockholders' equity | $ | 35,770 |
| | $ | 36,011 |
| $ | 32,527 |
| | $ | 32,311 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited) | | | Six Months Ended | Six Months Ended |
| June 30, | June 30, |
(In millions) | 2015 | | 2014 | 2016 | | 2015 |
Increase (decrease) in cash and cash equivalents | | | | | | |
Operating activities: | |
| | |
| |
| | |
|
Net income (loss) | $ | (662 | ) | | $ | 1,689 |
| $ | (577 | ) | | $ | (662 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |
| | |
| |
| | |
|
Discontinued operations | — |
| | (931 | ) | |
Deferred income taxes | (185 | ) | | 173 |
| (392 | ) | | (185 | ) |
Depreciation, depletion and amortization | 1,572 |
| | 1,323 |
| 1,170 |
| | 1,572 |
|
Impairments | 44 |
| | 21 |
| 1 |
| | 44 |
|
Net (gain) loss on derivative instruments | | 88 |
| | 17 |
|
Net cash received (paid) in settlement of derivative instruments | | 46 |
| | 4 |
|
Pension and other postretirement benefits, net | 14 |
| | 26 |
| 14 |
| | 14 |
|
Exploratory dry well costs and unproved property impairments | 148 |
| | 156 |
| 166 |
| | 148 |
|
Net (gain) loss on disposal of assets | (1 | ) | | 85 |
| (234 | ) | | (1 | ) |
Equity method investments, net | 37 |
| | (10 | ) | 22 |
| | 37 |
|
Changes in: | | | |
| | | |
|
Current receivables | 534 |
| | (266 | ) | 88 |
| | 534 |
|
Inventories | 21 |
| | (58 | ) | 30 |
| | 21 |
|
Current accounts payable and accrued liabilities | (770 | ) | | (31 | ) | (211 | ) | | (770 | ) |
All other operating, net | (35 | ) | | (59 | ) | 41 |
| | (56 | ) |
Net cash provided by continuing operations | 717 |
| | 2,118 |
| |
Net cash provided by discontinued operations | — |
| | 440 |
| |
Net cash provided by operating activities | 717 |
| | 2,558 |
| 252 |
| | 717 |
|
Investing activities: | |
| | |
| |
| | |
|
Additions to property, plant and equipment | (2,320 | ) | | (2,230 | ) | (753 | ) | | (2,320 | ) |
Disposal of assets | 2 |
| | 2,232 |
| 758 |
| | 2 |
|
Investments - return of capital | 31 |
| | 27 |
| 37 |
| | 31 |
|
Purchases of short-term investments | (925 | ) | | — |
| — |
| | (925 | ) |
Investing activities of discontinued operations | — |
| | (233 | ) | |
Deposit for acquisition | | (89 | ) | | — |
|
All other investing, net | (1 | ) | | — |
| 2 |
| | (1 | ) |
Net cash used in investing activities | (3,213 | ) | | (204 | ) | (45 | ) | | (3,213 | ) |
Financing activities: | |
| | |
| |
| | |
|
Commercial paper, net | — |
| | (135 | ) | |
Borrowings | 1,996 |
| | — |
| — |
| | 1,996 |
|
Debt issuance costs | (19 | ) | | — |
| — |
| | (19 | ) |
Debt repayments | (34 | ) | | (34 | ) | — |
| | (34 | ) |
Purchases of common stock | — |
| | (1,000 | ) | |
Common stock issuance | | 1,236 |
| | — |
|
Dividends paid | (285 | ) | | (260 | ) | (77 | ) | | (285 | ) |
All other financing, net | 11 |
| | 86 |
| — |
| | 11 |
|
Net cash provided by (used in) financing activities | 1,669 |
| | (1,343 | ) | 1,159 |
| | 1,669 |
|
Effect of exchange rate on cash and cash equivalents: | | | | |
Continuing operations | 1 |
| | — |
| |
Discontinued operations | — |
| | (10 | ) | |
Cash held for sale | — |
| | (96 | ) | |
Effect of exchange rate on cash and cash equivalents | | (3 | ) | | 1 |
|
Net increase (decrease) in cash and cash equivalents | (826 | ) | | 905 |
| 1,363 |
| | (826 | ) |
Cash and cash equivalents at beginning of period | 2,398 |
| | 264 |
| 1,221 |
| | 2,398 |
|
Cash and cash equivalents at end of period | $ | 1,572 |
| | $ | 1,169 |
| $ | 2,584 |
| | $ | 1,572 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
1. Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission ("SEC")SEC and do not include all of the information and disclosures required by accounting principles generally accepted in the United States ("U.S. GAAP")GAAP for complete financial statements.
AsA reclassification between operating cash flow categories was made to the prior year's financial information to present it on a result ofbasis comparable with the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations andcurrent year's presentation with no impact on net cash flows are presented on the basis of continuing operations, unless otherwise noted.provided by operating activities.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2014our 2015 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of 20152016 are not necessarily indicative of the results to be expected for the full year.
2. Accounting Standards
Not Yet Adopted
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 March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We continue to evaluate the provisions of this accounting standards update but do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. While early adoption is permitted, we plan to adopt in the first quarter of 2018. We continue to evaluate certain provisions of this accounting standards update and are assessing the impact it will have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will bewas applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will bewas no impact on our consolidated results of operations, financial position or cash flows.
In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted, including in interim periods. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine ifwhether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016 and early adoption is permitted, including in interim periods. We do not expect the2016. The adoption of this standard todid not have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States ("U.S.") auditing standards. This standard is effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter of 2017. 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.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Recently Adopted
In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required. In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact our consolidated results of operations, financial position or cash flows.
3. Variable Interest Entity
The owners of the Athabasca Oil Sands Project, ("AOSP"), in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at June 30, 20152016 and $3 million at December 31, 2014.2015. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $508$468 million as of June 30, 2015.2016. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
| |
4. | Income (Loss) per Common Share |
Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 514 million stock options for the second quarters of 2015three and 2014six month periods ended June 30, 2016 and 13 million and 4 million stock options for the firstthree and six month periods ended June 30, 2015 that were antidilutive.
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
(In millions, except per share data) | 2016 | | 2015 | | 2016 | | 2015 |
Net income (loss) | $ | (170 | ) | | $ | (386 | ) | | $ | (577 | ) | | $ | (662 | ) |
| | | | | | | |
Weighted average common shares outstanding | 848 |
| | 677 |
| | 790 |
| | 676 |
|
Weighted average common shares, diluted | 848 |
| | 677 |
| | 790 |
| | 676 |
|
Net income (loss) per share: | | | | | | | |
Basic | $ | (0.20 | ) | | $ | (0.57 | ) | | $ | (0.73 | ) | | $ | (0.98 | ) |
Diluted | $ | (0.20 | ) | | $ | (0.57 | ) | | $ | (0.73 | ) | | $ | (0.98 | ) |
5. Acquisitions
In June 2016, we executed a purchase agreement to acquire PayRock Energy Holdings, LLC ("PayRock"), a portfolio company of EnCap Investments, which closed on August 1, 2016 for $888 million, subject to closing adjustments. PayRock has approximately 61,000 net surface acres and current production of approximately 9,000 net barrels of oil equivalent in the oil window of the Anadarko Basin STACK play in Oklahoma. In the second quarter of 2016 an $89 million deposit was paid into escrow related to the acquisition. The purchase price was paid with cash on hand. We accounted for this transaction as an asset acquisition, with the majority of the purchase price allocated to property, plant and equipment.
2016 - North America E&P Segment
During the quarter, we announced the sale of our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter. A pre-tax gain of $266 million was recognized in the second quarter 2016. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. These assets are classified as held for sale in the consolidated balance sheet as of June 30, 2016 with total assets of $104 million and total liabilities of $4 million. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. We closed on certain of the asset sales and recognized a net pre-tax net loss on sale of $48 million for the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.
2015 - North America E&P Segment
In the third quarter of 2015, we closed on the sale of our East Texas/North Louisiana and 2014 that were antidilutive.Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets as a result of the anticipated sale (see Note 13). |
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
(In millions, except per share data) | 2015 | | 2014 | | 2015 | | 2014 |
Income (loss) from continuing operations | $ | (386 | ) | | $ | 360 |
| | $ | (662 | ) | | $ | 758 |
|
Discontinued operations | — |
| | 180 |
| | — |
| | 931 |
|
Net income (loss) | $ | (386 | ) | | $ | 540 |
| | $ | (662 | ) | | $ | 1,689 |
|
| | | | | | | |
Weighted average common shares outstanding | 677 |
| | 676 |
| | 676 |
| | 684 |
|
Effect of dilutive securities | — |
| | 3 |
| | — |
| | 4 |
|
Weighted average common shares, diluted | 677 |
| | 679 |
| | 676 |
| | 688 |
|
Per basic share: | | | | | | | |
Income (loss) from continuing operations | $ | (0.57 | ) | | $ | 0.53 |
| | $ | (0.98 | ) | | $ | 1.11 |
|
Discontinued operations | $ | — |
| | $ | 0.27 |
| | $ | — |
| | $ | 1.36 |
|
Net income (loss) | $ | (0.57 | ) | | $ | 0.80 |
| | $ | (0.98 | ) | | $ | 2.47 |
|
Per diluted share: | | | | | | | |
Income (loss) from continuing operations | $ | (0.57 | ) | | $ | 0.53 |
| | $ | (0.98 | ) | | $ | 1.10 |
|
Discontinued operations | $ | — |
| | $ | 0.27 |
| | $ | — |
| | $ | 1.36 |
|
Net income (loss) | $ | (0.57 | ) | | $ | 0.80 |
| | $ | (0.98 | ) | | $ | 2.46 |
|
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
2015 - North America E&P Segment
In July 2015, we entered into an agreement to sell our East Texas/North Louisiana and Wilburton, Oklahoma natural gas assets for expected proceeds of $102 million, excluding closing adjustments. We expect the transaction to close during the third quarter of 2015.
2014 - North America E&P Segment
In June 2014, we closed the sale of non-core acreage located in the far northwest portion of Williston Basin for proceeds of $90 million. A pretax loss of $91 million was recorded in the second quarter of 2014.
2014 - International E&P Segment
In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea. The transaction closed during the fourth quarter of 2014.
Our Norway business was reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2014. Select amounts reported in discontinued operations follow:
|
| | | | | | | | |
| Three Months Ended June 30, | Six Months Ended June 30, |
(In millions) | | 2014 | | 2014 |
Revenues applicable to discontinued operations | | $ | 693 |
| | $ | 1,373 |
|
Pretax income from discontinued operations | | $ | 598 |
| | $ | 1,130 |
|
After-tax income from discontinued operations (a) | | $ | 180 |
| | $ | 322 |
|
(a)Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.
In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.
Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the prior period. Select amounts reported in discontinued operations follow:
|
| | | |
| Six Months Ended June 30, |
(In millions) | 2014 |
Revenues applicable to discontinued operations | $ | 58 |
|
Pretax income from discontinued operations, before gain | $ | 51 |
|
Pretax gain on disposition of discontinued operations | $ | 470 |
|
After-tax income from discontinued operations | $ | 609 |
|
6.7. Segment Information
We are a global energy company with operations in North America, Europe and Africa.have three reportable operating segments. Each of our three reportable operatingthese segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North AmericaN.A. E&P ("N.A. E&P") – explores for, produces and markets crude oil and condensate, natural gas liquids ("NGLs")NGLs and natural gas in North America;
InternationalInt'l E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")LNG and methanol, in Equatorial Guinea ("E.G."); and
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income from continuing operations excludingwhich excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. OurA 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. GainsAdditionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oilcommodity derivative instruments, pension settlement losses or other items that affect comparability also(as determined by the CODM) are not allocated to operating segments.
As discussed in Note 5, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the International E&P segment for 2014.
| | | Three Months Ended June 30, 2015 | Three Months Ended June 30, 2016 |
| | | Not Allocated | | | | | Not Allocated | | |
(In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
Sales and other operating revenues | $ | 993 |
| | $ | 211 |
| | $ | 147 |
| | $ | (44 | ) | (c) | $ | 1,307 |
| $ | 617 |
| | $ | 159 |
| | $ | 185 |
| | $ | (91 | ) | (c) | $ | 870 |
|
Marketing revenues | 110 |
| | 30 |
| | 43 |
| | — |
| | 183 |
| 53 |
| | 23 |
| | 13 |
| | — |
| | 89 |
|
Total revenues | 1,103 |
| | 241 |
| | 190 |
| | (44 | ) | | 1,490 |
| 670 |
| | 182 |
| | 198 |
| | (91 | ) | | 959 |
|
Income from equity method investments | — |
| | 26 |
| | — |
| | — |
| | 26 |
| — |
| | 37 |
| | — |
| | — |
| | 37 |
|
Net gain on disposal of assets and other income | 11 |
| | 4 |
| | — |
| | — |
| | 15 |
| 2 |
| | 7 |
| | 1 |
| | 296 |
| (d) | 306 |
|
Less: | | | | | | | | | | | | | | | | | | |
Production expenses | 179 |
| | 64 |
| | 207 |
| | — |
| | 450 |
| 129 |
| | 56 |
| | 165 |
| | — |
| | 350 |
|
Marketing costs | 112 |
| | 29 |
| | 41 |
| | — |
| | 182 |
| 52 |
| | 23 |
| | 13 |
| | — |
| | 88 |
|
Exploration expenses | 91 |
| | 20 |
| | — |
| | — |
| | 111 |
| 37 |
| | 4 |
| | 7 |
| | 141 |
| (e) | 189 |
|
Depreciation, depletion and amortization | 634 |
| | 71 |
| | 35 |
| | 11 |
| | 751 |
| 433 |
| | 68 |
| | 49 |
| | 11 |
| | 561 |
|
Impairments | — |
| | — |
| | — |
| | 44 |
| (d) | 44 |
| |
Other expenses (a) | 99 |
| | 19 |
| | 9 |
| | 122 |
| (e) | 249 |
| 97 |
| | 22 |
| | 9 |
| | 99 |
| (f) | 227 |
|
Taxes other than income | 67 |
| | — |
| | 5 |
| | 6 |
| | 78 |
| 35 |
| | — |
| | 4 |
| | — |
| | 39 |
|
Net interest and other | — |
| | — |
| | — |
| | 58 |
| | 58 |
| — |
| | — |
| | — |
| | 86 |
| | 86 |
|
Income tax provision (benefit) | (23 | ) | | 27 |
| | (30 | ) | | 20 |
| (f) | (6 | ) | |
Segment income (loss) /Loss from continuing operations | $ | (45 | ) | | $ | 41 |
| | $ | (77 | ) | | $ | (305 | ) | | $ | (386 | ) | |
Income tax benefit | | (41 | ) | | (2 | ) | | (10 | ) | | (15 | ) | | (68 | ) |
Segment income (loss) / Net income (loss) | | $ | (70 | ) | | $ | 55 |
| | $ | (38 | ) | | $ | (117 | ) | | $ | (170 | ) |
Capital expenditures (b) | $ | 551 |
| | $ | 99 |
| | $ | 16 |
| | $ | 12 |
| | $ | 678 |
| $ | 153 |
| | $ | 12 |
| | $ | 7 |
| | $ | 5 |
| | $ | 177 |
|
| |
(a) | Includes other operating expenses and general and administrative expenses. |
| |
(c) | Unrealized loss on crude oilcommodity derivative instruments. |
| |
(d) | Proved property impairmentPrimarily related to partial sale of Wyoming upstream and midstream assets. (See Note 12).note 6.) |
| |
(e) | Includes pension settlement lossImpairments associated with decision to not drill remaining Gulf of $64 million (see Note 7).Mexico undeveloped leases. |
| |
(f) | Includes $135pension settlement loss of $31 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note(See note 8). |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2014 |
| | | Not Allocated | | |
(In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
Sales and other operating revenues | $ | 1,540 |
| | $ | 347 |
| | $ | 383 |
| | $ | — |
| | $ | 2,270 |
|
Marketing revenues | 540 |
| | 61 |
| | 17 |
| | — |
| | 618 |
|
Total revenues | 2,080 |
| | 408 |
| | 400 |
| | — |
| | 2,888 |
|
Income from equity method investments | — |
| | 120 |
| | — |
| | — |
| | 120 |
|
Net gain (loss) on disposal of assets and other income | 15 |
| | 15 |
| | 1 |
| | (98 | ) | (c) | (67 | ) |
Less: | | | | | | | | | |
Production expenses | 217 |
| | 99 |
| | 246 |
| | — |
| | 562 |
|
Marketing costs | 537 |
| | 60 |
| | 17 |
| | — |
| | 614 |
|
Exploration expenses | 82 |
| | 63 |
| | — |
| | — |
| | 145 |
|
Depreciation, depletion and amortization | 550 |
| | 75 |
| | 45 |
| | 10 |
| | 680 |
|
Impairments | 4 |
| | — |
| | — |
| | — |
| | 4 |
|
Other expenses (a) | 126 |
| | 34 |
| | 13 |
| | 67 |
| (d) | 240 |
|
Taxes other than income | 102 |
| | — |
| | 6 |
| | 1 |
| | 109 |
|
Net interest and other | — |
| | — |
| | — |
| | 76 |
| | 76 |
|
Income tax provision (benefit) | 175 |
| | 52 |
| | 19 |
| | (95 | ) | | 151 |
|
Segment income/Income from continuing operations | $ | 302 |
| | $ | 160 |
| | $ | 55 |
| | $ | (157 | ) | | $ | 360 |
|
Capital expenditures (b) | $ | 1,102 |
| | $ | 115 |
| | $ | 55 |
| | $ | 10 |
| | $ | 1,282 |
|
| |
(a)
| Includes other operating expenses and general and administrative expenses. |
| |
(c)
| Primarily related to the sale of non-core acreage (see Note 5). |
| |
(d)
| Includes pension settlement loss of $8 million (see Note 7). |
| | | Six Months Ended June 30, 2015 | Three Months Ended June 30, 2015 |
| | | Not Allocated | | | | | Not Allocated | | |
(In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
Sales and other operating revenues | $ | 1,843 |
| | $ | 393 |
| | $ | 372 |
| | $ | (21 | ) | (c) | $ | 2,587 |
| $ | 993 |
| | $ | 211 |
| | $ | 147 |
| | $ | (44 | ) | (c) | $ | 1,307 |
|
Marketing revenues | 288 |
| | 56 |
| | 43 |
| | — |
| | 387 |
| 110 |
| | 30 |
| | 43 |
| | — |
| | 183 |
|
Total revenues | 2,131 |
| | 449 |
| | 415 |
| | (21 | ) | | 2,974 |
| 1,103 |
| | 241 |
| | 190 |
| | (44 | ) | | 1,490 |
|
Income from equity method investments | — |
| | 62 |
| | — |
| | — |
| | 62 |
| — |
| | 26 |
| | — |
| | — |
| | 26 |
|
Net gain on disposal of assets and other income | 11 |
| | 14 |
| | 1 |
| | 1 |
| | 27 |
| 11 |
| | 4 |
| | — |
| | — |
| | 15 |
|
Less: | | | | | | | | | | | | | | | | | | |
Production expenses | 381 |
| | 131 |
| | 382 |
| | — |
| | 894 |
| 179 |
| | 64 |
| | 207 |
| | — |
| | 450 |
|
Marketing costs | 292 |
| | 54 |
| | 41 |
| | — |
| | 387 |
| 112 |
| | 29 |
| | 41 |
| | — |
| | 182 |
|
Exploration expenses | 126 |
| | 75 |
| | — |
| | — |
| | 201 |
| 91 |
| | 20 |
| | — |
| | — |
| | 111 |
|
Depreciation, depletion and amortization | 1,317 |
| | 135 |
| | 97 |
| | 23 |
| | 1,572 |
| 634 |
| | 71 |
| | 35 |
| | 11 |
| | 751 |
|
Impairments | — |
| | — |
| | — |
| | 44 |
| (d) | 44 |
| — |
| | — |
| | — |
| | 44 |
| (d) | 44 |
|
Other expenses (a) | 216 |
| | 42 |
| | 18 |
| | 251 |
| (e) | 527 |
| 99 |
| | 19 |
| | 9 |
| | 122 |
| (e) | 249 |
|
Taxes other than income | 128 |
| | — |
| | 10 |
| | 7 |
| | 145 |
| 67 |
| | — |
| | 5 |
| | 6 |
| | 78 |
|
Net interest and other | — |
| | — |
| | — |
| | 105 |
| | 105 |
| — |
| | — |
| | — |
| | 58 |
| | 58 |
|
Income tax provision (benefit) | (112 | ) | | 24 |
| | (36 | ) | | (26 | ) | (f) | (150 | ) | (23 | ) | | 27 |
| | (30 | ) | | 20 |
| (f) | (6 | ) |
Segment income (loss) /Loss from continuing operations | $ | (206 | ) | | $ | 64 |
| | $ | (96 | ) | | $ | (424 | ) | | $ | (662 | ) | |
Segment income (loss) / Net income (loss) | | $ | (45 | ) | | $ | 41 |
| | $ | (77 | ) | | $ | (305 | ) | | $ | (386 | ) |
Capital expenditures (b) | $ | 1,484 |
| | $ | 245 |
| | $ | 37 |
| | $ | 14 |
| | $ | 1,780 |
| $ | 551 |
| | $ | 99 |
| | $ | 16 |
| | $ | 12 |
| | $ | 678 |
|
| |
(a) | Includes other operating expenses and general and administrative expenses. |
| |
(c) | Unrealized loss on crude oilcommodity derivative instruments. |
| |
(d) | Proved property impairment (See Note 12)13). |
| |
(e) | Includes $43 million of severance related expenses associated with a workforce reduction and a pension settlement loss of $81$64 million (see Note 7)8). |
| |
(f) | Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 8)9). |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
| | | Six Months Ended June 30, 2014 | Six Months Ended June 30, 2016 |
| | | Not Allocated | | | | | Not Allocated | | |
(In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
Sales and other operating revenues | $ | 2,932 |
| | $ | 727 |
| | $ | 760 |
| | $ | — |
| | $ | 4,419 |
| $ | 1,110 |
| | $ | 255 |
| | $ | 333 |
| | $ | (114 | ) | (c) | $ | 1,584 |
|
Marketing revenues | 980 |
| | 131 |
| | 48 |
| | — |
| | 1,159 |
| 84 |
| | 38 |
| | 25 |
| | — |
| | 147 |
|
Total revenues | 3,912 |
| | 858 |
| | 808 |
| | — |
| | 5,578 |
| 1,194 |
| | 293 |
| | 358 |
| | (114 | ) | | 1,731 |
|
Income from equity method investments | — |
| | 257 |
| | — |
| | — |
| | 257 |
| — |
| | 51 |
| | — |
| | — |
| | 51 |
|
Net gain (loss) on disposal of assets and other income | 18 |
| | 32 |
| | 3 |
| | (98 | ) | (c) | (45 | ) | |
Net gain on disposal of assets and other income | | 3 |
| | 13 |
| | 1 |
| | 233 |
| (d) | 250 |
|
Less: | | | | | | | | | | | | | | | | | | |
Production expenses | 428 |
| | 199 |
| | 477 |
| | — |
| | 1,104 |
| 263 |
| | 109 |
| | 306 |
| | — |
| | 678 |
|
Marketing costs | 977 |
| | 131 |
| | 48 |
| | — |
| | 1,156 |
| 84 |
| | 37 |
| | 25 |
| | — |
| | 146 |
|
Exploration expenses | 139 |
| | 79 |
| | — |
| | — |
| | 218 |
| 55 |
| | 10 |
| | 7 |
| | 141 |
| (e) | 213 |
|
Depreciation, depletion and amortization | 1,065 |
| | 146 |
| | 90 |
| | 22 |
| | 1,323 |
| 920 |
| | 118 |
| | 109 |
| | 23 |
| | 1,170 |
|
Impairments | 21 |
| | — |
| | — |
| | — |
| | 21 |
| 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Other expenses (a) | 236 |
| | 72 |
| | 26 |
| | 196 |
| (d) | 530 |
| 215 |
| | 38 |
| | 16 |
| | 218 |
| (f) | 487 |
|
Taxes other than income | 192 |
| | — |
| | 11 |
| | 1 |
| | 204 |
| 77 |
| | — |
| | 9 |
| | 1 |
| | 87 |
|
Net interest and other | — |
| | — |
| | — |
| | 125 |
| | 125 |
| — |
| | — |
| | — |
| | 171 |
| | 171 |
|
Income tax provision (benefit) | 328 |
| | 139 |
| | 40 |
| | (156 | ) | | 351 |
| |
Segment income /Income from continuing operations | $ | 544 |
| | $ | 381 |
| | $ | 119 |
| | $ | (286 | ) | | $ | 758 |
| |
Income tax benefit | | (153 | ) | | (14 | ) | | (27 | ) | | (150 | ) | | (344 | ) |
Segment income (loss) / Net income (loss) | | $ | (265 | ) | | $ | 59 |
| | $ | (86 | ) | | $ | (285 | ) | | $ | (577 | ) |
Capital expenditures (b) | $ | 1,969 |
| | $ | 220 |
| | $ | 123 |
| | $ | 13 |
| | $ | 2,325 |
| $ | 468 |
| | $ | 44 |
| | $ | 16 |
| | $ | 8 |
| | $ | 536 |
|
| |
(a) | Includes other operating expenses and general and administrative expenses. |
(b)Includes accruals.
| |
(c) | Unrealized loss on commodity derivative instruments. |
| |
(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). |
|
| | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2015 |
| | | Not Allocated | | |
(In millions) | N.A. E&P | | Int'l E&P | | OSM | | to Segments | | Total |
Sales and other operating revenues | $ | 1,843 |
| | $ | 393 |
| | $ | 372 |
| | $ | (21 | ) | (c) | $ | 2,587 |
|
Marketing revenues | 288 |
| | 56 |
| | 43 |
| | — |
| | 387 |
|
Total revenues | 2,131 |
| | 449 |
| | 415 |
| | (21 | ) | | 2,974 |
|
Income from equity method investments | — |
| | 62 |
| | — |
| | — |
| | 62 |
|
Net gain on disposal of assets and other income | 11 |
| | 14 |
| | 1 |
| | 1 |
| | 27 |
|
Less: | | | | | | | | | |
Production expenses | 381 |
| | 131 |
| | 382 |
| | — |
| | 894 |
|
Marketing costs | 292 |
| | 54 |
| | 41 |
| | — |
| | 387 |
|
Exploration expenses | 126 |
| | 75 |
| | — |
| | — |
| | 201 |
|
Depreciation, depletion and amortization | 1,317 |
| | 135 |
| | 97 |
| | 23 |
| | 1,572 |
|
Impairments | — |
| | — |
| | — |
| | 44 |
| (d) | 44 |
|
Other expenses (a) | 216 |
| | 42 |
| | 18 |
| | 251 |
| (e) | 527 |
|
Taxes other than income | 128 |
| | — |
| | 10 |
| | 7 |
| | 145 |
|
Net interest and other | — |
| | — |
| | — |
| | 105 |
| | 105 |
|
Income tax provision (benefit) | (112 | ) | | 24 |
| | (36 | ) | | (26 | ) | (f) | (150 | ) |
Segment income (loss) / Net income (loss) | $ | (206 | ) | | $ | 64 |
| | $ | (96 | ) | | $ | (424 | ) | | $ | (662 | ) |
Capital expenditures (b) | $ | 1,484 |
| | $ | 245 |
| | $ | 37 |
| | $ | 14 |
| | $ | 1,780 |
|
| |
(a) | Includes other operating expenses and general and administrative expenses. |
| |
(c) | Primarily related to the sale of non-core acreage (see Note 5).Unrealized loss on commodity derivative instruments. |
| |
(d) | Proved property impairments (See Note 13). |
| |
(e) | Includes pension settlement loss of $71$81 million and severance related expenses associated with workforce reductions of $43 million (see Note 7)8). |
7. Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost (credit):
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, |
| Pension Benefits | | Other Benefits |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 |
Service cost | $ | 12 |
| | $ | 11 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 13 |
| | 15 |
| | 2 |
| | 3 |
|
Expected return on plan assets | (17 | ) | | (14 | ) | | — |
| | — |
|
Amortization: | |
| | |
| | |
| | |
|
– prior service cost (credit) | (2 | ) | | 2 |
| | (1 | ) | | (1 | ) |
– actuarial loss | 7 |
| | 10 |
| | — |
| | — |
|
Net settlement loss (a) | 64 |
| | 8 |
| | — |
| | — |
|
Net curtailment loss (b) | — |
| | — |
| | 2 |
| | — |
|
Net periodic benefit cost | $ | 77 |
| | $ | 32 |
| | $ | 4 |
| | $ | 3 |
|
| |
(f) | Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9). |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, |
| Pension Benefits | | Other Benefits |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 |
Service cost | 24 |
| | 23 |
| | 2 |
| | 2 |
|
Interest cost | 27 |
| | 31 |
| | 5 |
| | 6 |
|
Expected return on plan assets | (36 | ) | | (32 | ) | | — |
| | — |
|
Amortization: | |
| | |
| | |
| | |
|
– prior service cost (credit) | (1 | ) | | 3 |
| | (2 | ) | | (2 | ) |
– actuarial loss | 14 |
| | 16 |
| | — |
| | — |
|
Net settlement loss(a) | 81 |
| | 71 |
| | — |
| | — |
|
Net curtailment loss (gain) (b) | 1 |
| | — |
| | (4 | ) | | — |
|
Net periodic benefit cost | $ | 110 |
|
| $ | 112 |
|
| $ | 1 |
|
| $ | 6 |
|
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) | 2016 | | 2015 | | 2016 | | 2015 |
Service cost | $ | 6 |
| | $ | 12 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 10 |
| | 13 |
| | 2 |
| | 2 |
|
Expected return on plan assets | (13 | ) | | (17 | ) | | — |
| | — |
|
Amortization: | |
| | |
| | |
| | |
|
– prior service cost (credit) | (3 | ) | | (2 | ) | | (1 | ) | | (1 | ) |
– actuarial loss | 4 |
| | 7 |
| | — |
| | — |
|
Net settlement loss (a) | 31 |
| | 64 |
| | — |
| | — |
|
Net curtailment loss (b) | — |
| | — |
| | — |
| | 2 |
|
Net periodic benefit cost | $ | 35 |
| | $ | 77 |
| | $ | 2 |
| | $ | 4 |
|
|
| | | | | | | | | | | | | | | |
| Six Months Ended June 30, |
| Pension Benefits | | Other Benefits |
(In millions) | 2016 | | 2015 | | 2016 | | 2015 |
Service cost | $ | 12 |
| | $ | 24 |
| | $ | 2 |
| | $ | 2 |
|
Interest cost | 21 |
| | 27 |
| | 5 |
| | 5 |
|
Expected return on plan assets | (28 | ) | | (36 | ) | | — |
| | — |
|
Amortization: | | | |
| | |
| | |
|
– prior service cost (credit) | (5 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
– actuarial loss | 7 |
| | 14 |
| | — |
| | — |
|
Net settlement loss (a) | 79 |
| | 81 |
| | — |
| | — |
|
Net curtailment loss (gain) (b) | — |
| | 1 |
| | — |
| | (4 | ) |
Net periodic benefit cost | $ | 86 |
|
| $ | 110 |
|
| $ | 5 |
|
| $ | 1 |
|
| |
(a) | Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year. |
| |
(b) | Related to the workforce reduction,reductions, which reduced the future expected years of service for employees participating in the plans. |
During the first six months of 2015,2016, we recorded the effects of a workforce reduction and a pension plan amendment. The pension plan amendment freezes the final average pay used to calculate the formula benefit and is effective July 6, 2015. Additionally, during the first six months of 2015 and 2014, we recorded the effects of partial settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost (credit).cost.
During the first six months of 2015,2016, we made contributions of $46$30 million to our funded pension plans. We expect to make additional contributions up to an estimated $42$34 million to our funded pension plans over the remainder of 2015.2016. During the first six months of 2015,2016, we made payments of $42$37 million and $8$10 million related to unfunded pension plans and other postretirement benefit plans, respectively.
8.9. 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 (benefits) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.7.
Our effective income tax rates on continuing operations for the first six months of 2016 and 2015 were 37% and 2014 were 18% and 32%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first six months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be 15% and 34% for the first six months of 2015 and 2014. In Libya, considerable uncertainty remains around the timing of future production and sales levels. Reliable estimates of 20152016 and 20142015 Libyan annual ordinary income from our operations could not be made, and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, forthe tax benefit applicable to Libyan ordinary loss was
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
recorded as a discrete item in the first six months of 20152016 and 2014,2015. For the first six months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).
On Excluding Libya, the effective tax rates would be 36% and 15% for the first six months of 2016 and 2015. The change was driven by a shift in jurisdictional income and tax legislation enacted by the Alberta government on June 29, 2015 the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.
Deferred Tax Assets
In the second quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of approximately $1 billion associatedconnection with our Canadian operations toassessment 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 permanently reinvested outsiderealized. In the U.S. As such, noneevent it is more likely than not that some portion or all of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional netour deferred taxes have been recorded inwill not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the second quarter of 2015.carryforward period.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
9.10. Short-term Investments
As of June 30, 2015, ourwe held short-term investments are comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. The maturity dates range from September 2015 to October 2015. These short-term investments, arewhich were classified as held-to-maturity investments which areand recorded at amortized cost. The carrying valuescost, matured in the third quarter of our short-term investments approximate fair value.2015.
10.11. Inventories
Inventories of liquidLiquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. MaterialsSupplies and suppliesother 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, | June 30, | | December 31, |
(In millions) | 2015 | | 2014 | 2016 | | 2015 |
Liquid hydrocarbons, natural gas and bitumen | $ | 50 |
| | $ | 58 |
| $ | 31 |
| | $ | 35 |
|
Supplies and other items | 286 |
| | 299 |
| 241 |
| | 278 |
|
Inventories, at cost | $ | 336 |
| | $ | 357 |
| $ | 272 |
| | $ | 313 |
|
11.12. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
| | | June 30, | | December 31, | June 30, | | December 31, |
(In millions) | 2015 | | 2014 | 2016 | | 2015 |
North America E&P | $ | 16,757 |
| | $ | 16,717 |
| $ | 13,965 |
| | $ | 15,226 |
|
International E&P | 2,848 |
| | 2,741 |
| 2,479 |
| | 2,533 |
|
Oil Sands Mining | 9,401 |
| | 9,455 |
| 9,101 |
| | 9,197 |
|
Corporate | 115 |
| | 127 |
| 112 |
| | 105 |
|
Net property, plant and equipment | $ | 29,121 |
|
| $ | 29,040 |
| $ | 25,657 |
|
| $ | 27,061 |
|
Our Libya operations continue to be impacted by civil unrestunrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es-Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Earlier this year, an Internationally-backed Unity Government was established in December 2014, Libya’sTripoli. During the second quarter, the two National Oil Corporation once again declared force majeureCompanies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerableour Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.
As of June 30, 2015,2016, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 20142015 are 243235 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 continuescontinue to exceed the carrying value of $775 million by a material amount. However, changes in
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
management's forecast assumptions may cause us to reassess our assets in Libya for impairment, and could result in non-cash impairment charges in the future.
Exploratory well costs capitalized greater than one year after completion of drilling were $88$118 million and $126$85 million as of June 30, 20152016 and December 31, 2014. This $382015. The $33 million net decrease was associated with our Canadian in-situ assets at Birchwood. After further evaluationincrease primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the estimated recoverable resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ("SAGD") demonstration project.Alba Block Sub Area B exploration program.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
12.13. 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, 20152016 and December 31, 20142015 by fair value hierarchy level.
| | | June 30, 2015 | June 30, 2016 |
(In millions) | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
Derivative instruments, assets | | | | | | | | | | | | | | |
Commodity (a) | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
| $ | — |
| | $ | 6 |
| | $ | — |
| | $ | 6 |
|
Interest rate | — |
| | 11 |
| | — |
| | 11 |
| — |
| | 12 |
| | — |
| | 12 |
|
Derivative instruments, assets | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| $ | — |
| | $ | 18 |
| | $ | — |
| | $ | 18 |
|
Derivative instruments, liabilities | | | | | | | | | | | | | | |
Commodity (a) | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
| $ | — |
| | $ | 70 |
| | $ | — |
| | $ | 70 |
|
Derivative instruments, liabilities | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
| $ | — |
| | $ | 70 |
| | $ | — |
| | $ | 70 |
|
| |
(a) | Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 13)14). |
| | | December 31, 2014 | December 31, 2015 |
(In millions) | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
Derivative instruments, assets | | | | | | | | | | | | | | |
Commodity (a) | | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | 51 |
|
Interest rate | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | 8 |
| — |
| | 8 |
| | — |
| | 8 |
|
Derivative instruments, assets | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | 8 |
| $ | — |
| | $ | 59 |
| | $ | — |
| | $ | 59 |
|
Derivative instruments, liabilities | | | | | | | | |
Commodity (a) | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
Derivative instruments, liabilities | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| |
(a) | Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 14). |
Commodity derivatives include three-way collars, swaptions, extendable three-waytwo-way collars, call options and call options.swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include commodity prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs.
See Note 1314 for additional discussion of the types of derivative instruments we use.
Fair Values -– Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers 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 and operating expenses and tax rates. The assumptions used in the income approach
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
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 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded the book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values- Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
| | | Three Months Ended June 30, | Three Months Ended June 30, |
| 2015 | | 2014 | 2016 | | 2015 |
(In millions) | Fair Value | | Impairment | | Fair Value | | Impairment | Fair Value | | Impairment | | Fair Value | | Impairment |
Long-lived assets held for use | $ | 17 |
| | $ | 44 |
| | $ | — |
| | $ | 4 |
| $ | — |
| | $ | — |
| | $ | 17 |
| | $ | 44 |
|
| | | Six Months Ended June 30, | Six Months Ended June 30, |
| 2015 | | 2014 | 2016 | | 2015 |
(In millions) | Fair Value | | Impairment | | Fair Value | | Impairment | Fair Value | | Impairment | | Fair Value | | Impairment |
Long-lived assets held for use | $ | 17 |
| | $ | 44 |
| | $ | — |
| | $ | 21 |
| $ | — |
| | $ | 1 |
| | $ | 17 |
| | $ | 44 |
|
Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015 as compared to the first six months of 2014. As this period of sustained reduced commodity prices continues, it could result in non-cash impairment charges related to long-lived assets in future periods.
All long-livedLong-lived assets held for use that were impaired inare discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the first six months of 2015fair value measurement include reserve and 2014 were heldproduction estimates made by our North America E&P segment.
reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
In July 2015, we entered into an agreement to sell our East Texas/North Louisiana and Wilburton, Oklahoma natural gas assets. We expect the transaction to close during the third quarter of 2015. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to theseEast Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale.sale (See Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model. The held-for-use model contained internal estimates of future production levels, prices and discount rate. All such inputs were classified as Level 3.
The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first and second quarters of 2014, we recorded additional impairments of $17 million and $4 million as a result of estimated abandonment cost revisions. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, short-term investments, long-term debt due within one year, and payables. We believe the carrying values of our receivables short-term investments and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair valuevalues by individual balance sheet line item at June 30, 20152016 and December 31, 2014.2015.
| | | June 30, 2015 | | December 31, 2014 | June 30, 2016 | | December 31, 2015 |
| Fair | | Carrying | | Fair | | Carrying | Fair | | Carrying | | Fair | | Carrying |
(In millions) | Value | | Amount | | Value | | Amount | Value | | Amount | | Value | | Amount |
Financial assets | | | | | | | | | | | | | | |
Other noncurrent assets | $ | 134 |
| | $ | 133 |
| | $ | 132 |
| | $ | 129 |
| $ | 198 |
| | $ | 206 |
| | $ | 104 |
| | $ | 118 |
|
Total financial assets | 134 |
| | 133 |
| | 132 |
| | 129 |
| $ | 198 |
| | $ | 206 |
| | $ | 104 |
| | $ | 118 |
|
Financial liabilities | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
Other current liabilities | 13 |
| | 13 |
| | 13 |
| | 13 |
| $ | 25 |
| | $ | 24 |
| | $ | 34 |
| | $ | 33 |
|
Long-term debt, including current portion (a) | 8,720 |
| | 8,324 |
| | 6,887 |
| | 6,360 |
| 7,186 |
| | 7,291 |
| | 6,723 |
| | 7,291 |
|
Deferred credits and other liabilities | 73 |
| | 67 |
| | 69 |
| | 68 |
| 121 |
| | 117 |
| | 97 |
| | 95 |
|
Total financial liabilities | $ | 8,806 |
| | $ | 8,404 |
| | $ | 6,969 |
| | $ | 6,441 |
| $ | 7,332 |
| | $ | 7,432 |
| | $ | 6,854 |
| | $ | 7,419 |
|
(a) Excludes capital leases.leases, debt issuance costs and interest rate swap adjustments.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.
13.14. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 12.13. 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 as of June 30, 2015 and December 31, 2014.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | |
| June 30, 2015 | | |
(In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
Fair Value Hedges | | | | | | | |
Interest rate | $ | 11 |
| | $ | — |
| | $ | 11 |
| | Other noncurrent assets |
Total | $ | 11 |
|
| $ | — |
|
| $ | 11 |
| | |
sheets. | | | | June 30, 2016 | |
(In millions) | | Asset | | Liability | | Net Asset | | Balance Sheet Location |
Fair Value Hedges | | | | | | | |
Interest rate | | $ | 12 |
| | $ | — |
| | $ | 12 |
| | Other noncurrent assets |
Total Designated Hedges | | $ | 12 |
| | $ | — |
| | $ | 12 |
| |
| | | | | | | | | | | | |
| June 30, 2015 | | June 30, 2016 | |
(In millions) | Asset | | Liability | | Net Liability | | Balance Sheet Location | Asset | | Liability | | Net Liability | | Balance Sheet Location |
Not Designated as Hedges | | | | | | | | | | | | |
Commodity | $ | 5 |
| | $ | 17 |
| | $ | 12 |
| | Other current liabilities | $ | 6 |
| | $ | 39 |
| | $ | 33 |
| | Other current liabilities |
Commodity | — |
| | 9 |
| | 9 |
| | Other noncurrent liabilities | — |
| | 31 |
| | 31 |
| | Deferred credits and other liabilities |
Total | $ | 5 |
| | $ | 26 |
| | $ | 21 |
| | |
Total Not Designated as Hedges | | $ | 6 |
| | $ | 70 |
| | $ | 64 |
| |
|
| | | | | | | | | | | | | |
| December 31, 2014 | | |
(In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
Fair Value Hedges | | | | | | | |
Interest rate | $ | 8 |
| | $ | — |
| | $ | 8 |
| | Other noncurrent assets |
Total | $ | 8 |
| | $ | — |
| | $ | 8 |
| | |
|
| | | | | | | | | | | | | |
| December 31, 2015 | | |
(In millions) | Asset | | Liability | | Net Asset | | Balance Sheet Location |
Fair Value Hedges | | | | | | | |
Interest rate | $ | 8 |
| | $ | — |
| | $ | 8 |
| | Other noncurrent assets |
| | | | | | | |
Not Designated as Hedges | | | | | | | |
Commodity | $ | 51 |
| | $ | 1 |
| | $ | 50 |
| | Other current assets |
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements, as of June 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
| | | June 30, 2015 | | December 31, 2014 | June 30, 2016 | | December 31, 2015 |
| Aggregate Notional Amount | Weighted Average, LIBOR-Based, | | Aggregate Notional Amount | Weighted Average, LIBOR-Based, | Aggregate Notional Amount | Weighted Average, LIBOR-Based, | | Aggregate Notional Amount | Weighted Average, LIBOR-Based, |
Maturity Dates | (in millions) | Floating Rate | | (in millions) | Floating Rate | (in millions) | Floating Rate | | (in millions) | Floating Rate |
October 1, 2017 | $ | 600 |
| 4.67 | % | | $ | 600 |
| 4.64 | % | $ | 600 |
| 4.94 | % | | $ | 600 |
| 4.73 | % |
March 15, 2018 | $ | 300 |
| 4.52 | % | | $ | 300 |
| 4.49 | % | $ | 300 |
| 4.77 | % | | $ | 300 |
| 4.66 | % |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.
| | | | Gain (Loss) | | Gain (Loss) |
| | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(In millions) | Income Statement Location | 2015 | | 2014 | | 2015 | | 2014 | Income Statement Location | 2016 | | 2015 | | 2016 | | 2015 |
Derivative | | | | | | | | | | | | | | | | |
Interest rate | Net interest and other | $ | (2 | ) | | $ | 4 |
| | $ | 3 |
| | $ | 3 |
| Net interest and other | $ | — |
| | $ | (2 | ) | | $ | 4 |
| | $ | 3 |
|
Foreign currency | Discontinued operations | $ | — |
| | $ | (14 | ) | | $ | — |
| | $ | (11 | ) | |
Hedged Item | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Long-term debt | Net interest and other | $ | 2 |
| | $ | (4 | ) | | $ | (3 | ) | | $ | (3 | ) | Net interest and other | $ | — |
| | $ | 2 |
| | $ | (4 | ) | | $ | (3 | ) |
Accrued taxes | Discontinued operations | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | 11 |
| |
Derivatives not Designated as Hedges
During the first six months of 2015, weWe have entered into multiple crude oil and natural gas derivatives indexed to New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI"),NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December 2016.2017. These commodity derivatives primarily consist of three-way collars, two-way collars, call options and three way-collars whichswaptions. 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 crude oil volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
In this case, we receive the NYMEX WTIWTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedgeshedges. The following table sets forth outstanding derivative contracts as of June 30, 2016 and are shown in the table below:weighted average prices for those contracts:
| | Financial Instrument | Weighted Average Price | Barrels per day | Remaining Term | |
Crude Oil | | Crude Oil |
| | | Year Ending December 31, |
| | Third Quarter | Fourth Quarter | 2017 |
Three-Way Collars | | Three-Way Collars |
Volume (Bbls/day) | | 47,000 | — |
Price per Bbl: | | |
Ceiling | $70.34 | 35,000 | July- December 2015 (a) | $55.37 | — |
Floor | $55.57 | | $50.23 | — |
Sold put | $41.29 | | $40.96 | — |
| | |
Sold call options (a) | | |
Volume (Bbls/day) | | 10,000 | 35,000 |
Price per Bbl | | $72.39 | $61.91 |
Two-way Collars | | |
Volume (Bbls/day) | | 10,000 | — |
Price per Bbl: | | |
| — |
Ceiling | $71.84 | 12,000 | January- December 2016 | $50.00 | |
Floor | $60.48 | | $41.55 | |
Sold put | $50.00 | | |
| | |
Ceiling | $73.13 | 2,000 | January- June 2016 (b) | |
Floor | $65.00 | | |
Sold put | $50.00 | | |
Call Options | $72.39 | 10,000 | January- December 2016 (c) | |
| |
(a) | Counterparties haveCall options settle monthly. |
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
|
| | | |
Natural Gas |
| | Year Ending December 31, |
| Third Quarter | Fourth Quarter | 2017 |
Three-Way Collars (a) | | | |
Volume (MMBtu/day) | 20,000 | 20,000 | 40,000 |
Price per MMBtu | | | |
Ceiling | $2.93 | $2.93 | $3.28 |
Floor | $2.50 | $2.50 | $2.75 |
Sold put | $2.00 | $2.00 | $2.25 |
| |
(a) | On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $71.67$2.93 per barrelMMBtu indexed to NYMEX WTI,Henry Hub, which is exercisable on October 30, 2015.December 22, 2016. If counterparties exercise,counterparty exercises, the term of the fixed pricefixed-price swaps would be for the calendar year 20162017 and, if all such options are exercised, 25,000 barrels20,000 MMBtu per day. |
| |
(b)
| Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars. |
| |
(c)
| Call options settle monthly. |
The mark-to-market impact of these crude oilcommodity 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, 2016 was a net loss of $88 million and $90 million compared to a net loss of $43 million and $17 million for the same respective periods in the second quarter and first six months2015. Net cash received from settlements of 2015. There were no crude oilcommodity derivative instruments infor the firstthree and six months of 2014.
Onmonth periods ended June 1, 2015, we entered into Treasury rate locks, which expired on the same day,30, 2016 was $14 million and $46 million compared to hedge against timing differences as it related to our Notes offering (see Note 15). Following the execution$4 million for both of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resultedrespective periods in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.2015.
14.15. Incentive Based Compensation
Stock optionoptions, restricted stock awards and restricted stock awardsunits
The following table presents a summary of stock option and restricted stock award activity for the first six months of 2015:2016:
| | | Stock Options | | Restricted Stock | Stock Options | | Restricted Stock Awards & Units |
| Number of Shares | | Weighted Average Exercise Price | | Awards | | Weighted Average Grant Date Fair Value | Number of Shares | | Weighted Average Exercise Price | | Awards | | Weighted Average Grant Date Fair Value |
Outstanding at December 31, 2014 | 13,427,836 |
| |
| $29.68 |
| | 3,448,353 |
| |
| $34.04 |
| |
Outstanding at December 31, 2015 | | 12,665,419 |
| |
| $29.97 |
| | 4,017,344 |
| |
| $30.76 |
|
Granted | 724,082 |
| (a) |
| $29.06 |
| | 2,668,357 |
| |
| $30.53 |
| 1,680,000 |
| (a) |
| $7.22 |
| | 5,233,984 |
| |
| $7.91 |
|
Options Exercised/Stock Vested | (480,458 | ) | |
| $16.47 |
| | (921,404 | ) | |
| $34.29 |
| — |
| | — |
| | (1,148,953 | ) | |
| $32.29 |
|
Canceled | (455,855 | ) | |
| $34.48 |
| | (491,739 | ) | |
| $33.70 |
| (973,295 | ) | |
| $25.76 |
| | (557,051 | ) | |
| $23.20 |
|
Outstanding at June 30, 2015 | 13,215,605 |
| |
| $29.97 |
| | 4,703,567 |
| |
| $32.04 |
| |
Outstanding at June 30, 2016 | | 13,372,124 |
| |
| $27.42 |
| | 7,545,324 |
| |
| $15.23 |
|
(a) The weighted average grant date fair value of stock option awards granted was $6.84$1.97 per share.
Stock-based performance unit awards
During the first six months of 2015,2016, we granted 382,3351,205,517 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.$3.72.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
15.16. Debt
Revolving Credit Facility
As of June 30, 2015,2016, we had no borrowings against our revolving credit facility (as amended, the(the "Credit Facility"), as described below.
In May 2015,March 2016, we amendedincreased our $2.5$3.0 billion unsecured Credit Facility to increase the facility size by $500$300 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.$3.3 billion.
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, 2015,2016, we were in compliance with this covenant with a debt-to-capitalization ratio of 29%28%.
MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
Debt Issuance On June 10,
In the second quarter of 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:
•$600 million of 2.70% senior notes due June 1, 2020
•$900 million of 3.85% senior notes due June 1, 2025
•$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We will useand used the aggregate net proceeds to repay our $1 billion 0.90% senior notes due 2015, which mature on November 1, 2015, and for general corporate purposes. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. As of June 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.
16.17. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:loss:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Three Months Ended June 30, | | Six Months Ended June 30, | |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | | Income Statement Line | 2016 | | 2015 | | 2016 | | 2015 | | Income Statement Line |
| | | | |
Postretirement and postemployment plans | Postretirement and postemployment plans | | | | | | | | Postretirement and postemployment plans | | | | | | | |
Amortization of actuarial loss | $ | (7 | ) | | $ | (10 | ) | | $ | (14 | ) | | $ | (16 | ) | | General and administrative | $ | (4 | ) | | $ | (7 | ) | | $ | (7 | ) | | $ | (14 | ) | | General and administrative |
Net settlement loss | (64 | ) | | (8 | ) | | (81 | ) | | (71 | ) | | General and administrative | (31 | ) | | (64 | ) | | (79 | ) | | (81 | ) | | General and administrative |
Net curtailment gain (loss) | (2 | ) | | — |
| | 3 |
| | — |
| | General and administrative | — |
| | (2 | ) | | — |
| | 3 |
| | General and administrative |
| (73 | ) | | (18 | ) | | (92 | ) | | (87 | ) | | Income (loss) from operations | (35 | ) | | (73 | ) | | (86 | ) | | (92 | ) | | Income (loss) from operations |
| 25 |
| | 7 |
| | 32 |
| | 30 |
| | Benefit for income taxes | 13 |
| | 25 |
| | 29 |
| | 32 |
| | Provision (benefit) for income taxes |
Other insignificant, net of tax | — |
| | — |
| | — |
| | (1 | ) | | |
Total reclassifications | $ | (48 | ) | | $ | (11 | ) | | $ | (60 | ) | | $ | (58 | ) | | Income (loss) from continuing operations | |
Total reclassifications to expense | | $ | (22 | ) | | $ | (48 | ) | | $ | (57 | ) | | $ | (60 | ) | | Net income (loss) |
MARATHON OIL CORPORATION18. Stockholder's Equity
NotesIn 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 Consolidated Financial Statements (Unaudited)strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.
17.19. Supplemental Cash Flow Information |
| | | | | | | |
| Six Months Ended June 30, |
(In millions) | 2015 | | 2014 |
Net cash used in operating activities: | | | |
Interest paid (net of amounts capitalized) | $ | (143 | ) | | $ | (149 | ) |
Income taxes paid to taxing authorities (a) | (165 | ) | | (1,336 | ) |
Net cash provided by (used in) financing activities: | | | |
Commercial paper, net: | |
| | |
|
Issuances | $ | — |
| | $ | 2,285 |
|
Repayments | — |
| | (2,420 | ) |
Commercial paper, net | $ | — |
| | $ | (135 | ) |
Noncash investing activities, related to continuing operations: | |
| | |
|
Asset retirement costs capitalized, net of revisions | $ | 6 |
| | $ | 42 |
|
Asset retirement obligations assumed by buyer | — |
| | 52 |
|
Receivable for disposal of assets | — |
| | 44 |
|
|
| | | | | | | |
| Six Months Ended June 30, |
(In millions) | 2016 | | 2015 |
Net cash (used in) operating activities: | | | |
Interest paid (net of amounts capitalized) | $ | (177 | ) | | $ | (143 | ) |
Income taxes paid to taxing authorities | (61 | ) | | (165 | ) |
Noncash investing activities: | |
| | |
|
Asset retirement cost increase | $ | 2 |
| | $ | 6 |
|
Asset retirement obligations assumed by buyer | 83 |
| | — |
|
| |
(a)
| The first six months of 2014 included $1.076 billion related to discontinued operations. |
18.20. Commitments and Contingencies
We are a defendant in a number of lawsuitslegal 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.
21. Subsequent Event
During the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in other operating expense in that quarter.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 aan independent global energyexploration and production company based in Houston, Texas with operations in North America, Europe and Africa. Each of our three reportable operating segments is organizedAfrica and managed based upon both geographic locationa focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were $33 billion at June 30, 2016.
Our significant strategic actions and financial results include the nature of the productsfollowing:
Strengthened balance sheet
| |
◦ | At the end of the second quarter of 2016, we had $5.9 billion of liquidity, comprised of $2.6 billion in cash and an undrawn $3.3 billion revolving credit facility |
| |
◦ | Cash-adjusted debt-to-capital ratio of 20% at June 30, 2016, as compared with 25% at December 31, 2015 |
Focused on cost reductions
| |
◦ | Production expenses per boe in the second quarter of 2016, as compared to the same period last year improved in the North America E&P segment by 13% to $6.28 per boe and in the International E&P segment by 22% to $5.09 per boe |
| |
◦ | 2016 Capital Program reduced by $100 million to $1.3 billion |
| |
◦ | Eagle Ford completed well costs down 30% to $4.2 million versus the same quarter last year |
Simplifying and services it offers.concentrating portfolio
| |
◦ | Closed on the PayRock acquisition of STACK assets in Oklahoma for $888 million, funded with cash on hand |
| |
◦ | Entered into agreements for over $1 billion of transaction value related to non-core asset sales; already received over $800 million in proceeds through August 1, 2016 |
Major Project updates
| |
◦ | Alba B3 compression project in E.G., designed to maintain the production plateau two additional years and extend field life up to eight years, was completed within budget and on schedule with first gas in July |
| |
◦ | Outside-operated Gunflint development project in the Gulf of Mexico achieved first oil in July |
Financial results
| |
◦ | Cash provided by operating activities of $252 million for the first six months of 2016, despite average crude oil and condensate price realizations of $35.27 per bbl. |
| |
◦ | Net loss per share of $0.20 in the second quarter of 2016 as compared to net loss per share of $0.57 in the same period last year. Included in the second quarter 2016 net loss are: |
| |
▪ | Unrealized losses from our commodity derivative instruments totaling $91 million, pre-tax |
| |
▪ | Net gains on disposal of non-core assets totaling $294 million, pre-tax |
| |
▪ | Non-cash impairments totaling $141 million, pre-tax, as a result of our decision not to drill any of our remaining Gulf of Mexico leases |
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.
Executive OverviewOutlook
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and their subsequent reinvestmentthe amount of capital available to reinvest into our business. Commodity prices began decliningOur focus continues on the strengthening of the balance sheet, the simplification and concentration of our portfolio and cost reductions which during the second quarter of 2016 included a reduction to our Capital Program of $100 million to $1.3 billion for the year.
Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In second halfquarter of 2014 and remain substantially lower through 2015 as compared2016, we made the decision to the first six monthsnot drill our remaining Gulf of 2014. We believeMexico undeveloped leases. As a result, we can manage in this lower commodity price cycle throughrecorded a continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.
Our significant financial results, operating activities and strategic actions include the following:
Increased company-wide net sales volumes from continuing operations by 4% to 411 thousand barrelsnon-cash impairment of oil equivalent per day ("mboed")$141 million in the second quarter of 2015 from 394 mboed2016. Additionally, during the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in the second quarter of 2014
| |
◦ | Net sales volumes from our three U.S. resource plays increased 29% to 220 mboed in the second quarter of 2015 from 170 mboed in the second quarter of 2014
|
Maintained focus on cost discipline and efficiencies
| |
◦ | Reduced North America E&P production expenses per boe by 31% in the second quarter of 2015 compared to the same period last year |
| |
◦ | Achieved 96% average operational availability for our operated assets in the second quarter of 2015 |
| |
◦ | Reallocated an additional $35 million of capital to Oklahoma Resource Basins to leverage higher non-operated activity and to further advance subsurface knowledge and resource delineation |
Active management of liquidity and capital structure
| |
◦ | $5.5 billion of liquidity at the end of the second quarter, comprised of $3.0 billion in the unused revolving credit facility and $2.5 billion in cash and short-term investments |
| |
◦ | Cash and short-term investments-adjusted debt-to-capital ratio of 22% at June 30, 2015, as compared with 16% at December 31, 2014 |
| |
◦ | Issued $2 billion of senior notes in June 2015; plan to use $1 billion of proceeds to satisfy scheduled debt maturities in the fourth quarter of 2015 and the remainder for general corporate purposes |
| |
◦ | Increased the capacity of the revolving credit facility to $3.0 billion from $2.5 billion while also extending the maturity date to May 2020 |
| |
◦ | Repatriated Canadian earnings in tax efficient manner, providing $250 million of cash available for use in U.S. operations |
| |
◦ | Executed additional derivative instruments to reduce commodity price uncertainty for a portion of our forecasted North America E&P crude oil volumes |
Portfolio management activities
| |
◦ | We are targeting to generate at least $500 million from select non-core asset sales |
| |
◦ | Signed definitive sales agreement in July 2015 related to non-core assets for expected proceeds of $102 million, excluding closing-adjustments |
Financial results
| |
◦ | Loss from continuing operations per diluted share of $0.57 in the second quarter of 2015 as compared to income from continuing operations of $0.53 per diluted share in the same period last year |
| |
◦ | Recognized additional non-cash deferred tax expense of $135 million in the second quarter of 2015 related to the increase in Alberta's provincial corporate income tax rate |
| |
◦ | Operating cash flow provided by continuing operations for the first six months of 2015 was $717 million, compared to $2.1 billion in the same period last year, reflecting the lower commodity price environment |
other operating expense in that quarter.
We continue to optimize our resource allocation given the current price environment. We expect our full-year 2015 capital, investment and exploration budget to be at or below $3.3 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 375 - 390 net mboed.
Operations
North America E&P--ProductionThe following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.
|
| | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
Net Sales Volumes | 2016 | | 2015 | | Increase (Decrease) | | 2016 | | 2015 | | Increase (Decrease) |
North America E&P (mboed) | 224 | | 274 | | (18)% | | 232 | | 278 | | (17)% |
International E&P (mboed) | 120 | | 108 | | 11% | | 108 | | 112 | | (4)% |
Oil Sands Mining (mbbld) (a) | 49 | | 29 | | 69% | | 54 | | 44 | | 23% |
Total (mboed) | 393 | | 411 | | (4)% | | 394 | | 434 | | (9)% |
(a) Includes blendstocksNorth America E&P
Net sales volumes in the segment average net sales volumeswere lower in the second quarter and first six months of 2015 increased 21%2016 primarily as a result of decreased drilling and 26% comparedcompletion activity resulting in fewer wells brought to sales as well as 17 mboed relating to dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma) during the second quarter and first six monthshalf of 2014. Net liquid hydrocarbon2015. The following tables provide details regarding net sales volumes, increased 35 thousand barrels per day ("mbbld")sales mix and 47 mbbld, and net natural gas sales volumes increased 67 million cubic feet per day ("mmcfd") and 63 mmcfd in the second quarter and first six months of 2015 compared to the second quarter and first six months of 2014, reflecting continued growth from the combined U.S. resource plays.operational drilling activity for our significant operations within this segment:
|
| | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
Net Sales Volumes | 2016 | | 2015 | | Increase (Decrease) | | 2016 | | 2015 | | Increase (Decrease) |
Equivalent Barrels (mboed) | | | | | | | | | | | |
Eagle Ford | 109 | | 135 | | (19)% | | 114 | | 141 | | (19)% |
Oklahoma Resource Basins | 27 | | 24 | | 13% | | 27 | | 24 | | 13% |
Bakken | 53 | | 61 | | (13)% | | 55 | | 59 | | (7)% |
Other North America (a) | 35 | | 54 | | (35)% | | 36 | | 54 | | (33)% |
Total North America E&P | 224 | | 274 | | (18)% | | 232 | | 278 | | (17)% |
|
| | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Net Sales Volumes | | | | | | | |
Crude Oil and Condensate (mbbld) | | | | | | | |
Bakken | 54 | | 44 | | 53 | | 41 |
Eagle Ford | 82 | | 67 | | 87 | | 65 |
Oklahoma Resource Basins | 5 | | 2 | | 5 | | 2 |
Other North America (a) | 35 | | 38 | | 35 | | 36 |
Total Crude Oil and Condensate | 176 | | 151 | | 180 | | 144 |
Natural Gas Liquids (mbbld) | | | | | | | |
Bakken | 3 | | 3 | | 3 | | 2 |
Eagle Ford | 26 | | 16 | | 26 | | 16 |
Oklahoma Resource Basins | 6 | | 6 | | 6 | | 5 |
Other North America(a) | 2 | | 2 | | 3 | | 4 |
Total Natural Gas Liquids | 37 | | 27 | | 38 | | 27 |
Total Liquid Hydrocarbons (mbbld) | | | | | | | |
Bakken | 57 | | 47 | | 56 | | 43 |
Eagle Ford | 108 | | 83 | | 113 | | 81 |
Oklahoma Resource Basins | 11 | | 8 | | 11 | | 7 |
Other North America(a) | 37 | | 40 | | 38 | | 40 |
Total Liquid Hydrocarbons | 213 | | 178 | | 218 | | 171 |
Natural Gas (mmcfd) | | | | | | | |
Bakken | 22 | | 18 | | 20 | | 17 |
Eagle Ford | 164 | | 111 | | 167 | | 109 |
Oklahoma Resource Basins | 81 | | 61 | | 79 | | 58 |
Other North America(a) | 94 | | 104 | | 94 | | 113 |
Total Natural Gas | 361 | | 294 | | 360 | | 297 |
Equivalent Barrels (mboed) | | | | | | | |
Bakken | 61 | | 50 | | 59 | | 46 |
Eagle Ford | 135 | | 102 | | 141 | | 99 |
Oklahoma Resource Basins | 24 | | 18 | | 24 | | 17 |
Other North America(a) | 54 | | 57 | | 54 | | 58 |
Total North America E&P | 274 | | 227 | | 278 | | 220 |
(a) Includes 17 mboed of Gulf of Mexico and other conventional onshore U.S. production.
The following table presents a summaryproduction, which was disposed of our operated drilling activity induring the U.S. resource plays:
|
| | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Gross Operated | | | | | | | |
Eagle Ford: | | | | | | | |
Wells drilled to total depth | 59 | | 88 | | 147 | | 171 |
Wells brought to sales | 52 | | 76 | | 143 | | 125 |
Bakken: | | | | | | | |
Wells drilled to total depth | 5 | | 19 | | 25 | | 22 |
Wells brought to sales | 22 | | 19 | | 46 | | 16 |
Oklahoma Resource Basins: | | | | | | | |
Wells drilled to total depth | 5 | | 6 | | 13 | | 11 |
Wells brought to sales | 3 | | 4 | | 8 | | 8 |
Eagle Ford – Average net sales volumes from Eagle Ford were 135 mboed and 141 mboedsale of non-core assets in the second quarter and first six monthshalf of 2015 compared2015.
|
| | | | | |
| Three Months Ended June 30, 2016 |
Sales Mix - U.S. Resource Plays | Crude oil and condensate | | Natural gas liquids | | Natural gas |
| | | | | |
Eagle Ford | 56% | | 21% | | 23% |
Oklahoma Resource Basins | 21% | | 29% | | 50% |
Bakken | 83% | | 9% | | 8% |
|
| | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | 2016 | | 2015 |
Gross Operated | | | | | | | |
Eagle Ford: | | | | | | | |
Wells drilled to total depth | 40 | | 59 | | 98 | | 147 |
Wells brought to sales | 30 | | 52 | | 80 | | 143 |
Oklahoma Resource Basins: | | | | | | | |
Wells drilled to total depth | 6 | | 5 | | 11 | | 13 |
Wells brought to sales | 5 | | 3 | | 8 | | 8 |
Bakken: | | | | | | | |
Wells drilled to total depth | — | | 5 | | 3 | | 25 |
Wells brought to sales | 4 | | 22 | | 10 | | 46 |
Eagle Ford – Of the 30 gross operated wells brought to 102 mboed and 99 mboed insales during the same periods of 2014, for increases of 32% and 42%. Approximately 61% of second quarter of 2016, 19 were Lower Eagle Ford, 3 were Upper Eagle Ford and 8 were Austin Chalk. Production decreases were due to lower completion activity with fewer gross operated wells brought to sales was crude oil and condensate, 19% was NGLs and 20% was natural gas.reduced contribution from 2015 high-density pads drilled at tighter well spacing. Our average time to drill an Eagle Ford well in the second quarter 2015,2016, spud-to-total depth, was 8 days, a decrease from 11 days. Also, during the second quarter of 2015, we brought online 8 Upper Eagle Ford, 33 Lower Eagle Ford and 11 Austin Chalk gross operated wells and we completed and brought online three "stack-and-frac" pilots with wells in three horizons.
Bakken – Average net sales volumes from the Bakken shale were 61 mboed and 59 mboed in the second quarter and first six months of 2015 compared to 50 mboed and 46 mboeddays in the same period for 2014, for increasesquarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 22% and 28%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 13 days in the second quarter of 2015.2,400 feet per day.
Application of the enhanced completion design continues to provide promising results, with outperformance of historical type curves after 180 days of cumulative production. The enhanced completion design optimizes proppant loading, frac fluid volumes and stage density. Three high-density pilots (six wells per horizon) were completed through the second quarter. Also in the second quarter, our first Three Forks second bench well in the Myrmidon was completed.
Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 24 mboed in both the second quarter and first six months of 2015 compared to 18 mboed and 17 mboed in the comparable 2014 periods, for increases of 33% and 41%. Our second quarter 2015 production was approximately 20% crude, 25% NGLs and 55% natural gas. Of the three5 gross operated wells brought to sales thisin the second quarter twoof 2016, 3 were SCOOP wells and one was a STACK Osage well. We also finished drilling five operated Smith infill pilot wells this quarter.
Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 85 outside-operated wells in 2015 in the SCOOP Woodford, SCOOP SpringerWoodford; 2 were in the STACK Meramec and STACK areas. In the first six months of 2015, weall were extended laterals. We also participated in four16 outside-operated high-density spacing pilotswells during the second quarter of 2016, 10 of which were in the SCOOP area; threeand 6 were in the Woodford (80-128 acre spacing) and oneSTACK.
We closed on the Payrock acquisition in the emerging Springer shale (105-128 acre spacing) overlayingSTACK play in Oklahoma on August 1, 2016 and continue to operate one drilling rig on the Woodford. Two outside-operated STACK Meramec XLacreage with plans to add another rig late in the third quarter. This will bring the total rig count in Oklahoma to 4.
Bakken – Of the 4 gross operated wells were brought to sales duringin the quarter.second quarter of 2016, 2 were in the Middle Bakken formation and 2 in the Three Forks formation, all with higher intensity completions. We do not currently have an active drilling rig in the Bakken.
Other North America – Net sales volumes declined in the second quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico, – Development work continues inEast Texas, North Louisiana and Wilburton, Oklahoma. On June 30, we closed the sale of certain of our Wyoming upstream and midstream assets. Net sales volumes for all of our Wyoming assets were approximately 16 mboed for the second quarter and first half of 2016.
The Gunflint field, located onin Mississippi Canyon Blocksblock 948 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete in the second halfGulf of 2015.Mexico, achieved first production in July 2016. Full production is expected to reach at least 20 mboed gross with oil representing approximately 75% of the volumes produced. We hold an 18% non-operated working interest in the Gunflint field.
North America E&P--Exploration
Gulf of Mexico – During the second quarter, we spud the Solomon exploration prospect on Walker Ridge Block 225 and farmed down our operated working interest to 58%.
The third appraisal well on the Shenandoah prospect was spud in May 2015 and is still drilling. The well is located in Walker Ridge Block 52, in which we hold a 10% non-operated working interest.
International E&P--Production
International E&P segment average net
Net sales volumes in the second quarter and first six months of 2015 decreased 12% and 10% compared to the second quarter and first six months of 2014, reflecting field decline and a planned turnaround in Equatorial Guineasegment were higher in the second quarter of 2015, which also reduced sales to the AMPCO and LNG facilities. In addition, the AMPCO methanol facility completed2016 primarily as a result of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities in firstthe second quarter of 2015. 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, |
| 2015 | | 2014 | | 2015 | | 2014 |
Net Sales Volumes | | | | | | | |
Crude Oil and Condensate (mbbld) | | | | | | | |
Equatorial Guinea | 19 |
| | 20 |
| | 18 |
| | 22 |
|
United Kingdom | 14 |
| | 13 |
| | 14 |
| | 13 |
|
Total Crude Oil and Condensate | 33 |
| | 33 |
| | 32 |
| | 35 |
|
Natural Gas Liquids (mbbld) | | | | | | | |
Equatorial Guinea | 9 |
| | 11 |
| | 10 |
| | 11 |
|
United Kingdom | — |
| | — |
| | — |
| | — |
|
Total Natural Gas Liquids | 9 |
| | 11 |
| | 10 |
| | 11 |
|
Total Liquid Hydrocarbons (mbbld) | | | | | | | |
Equatorial Guinea | 28 |
| | 31 |
| | 28 |
| | 33 |
|
United Kingdom | 14 |
| | 13 |
| | 14 |
| | 13 |
|
Total Liquid Hydrocarbons | 42 |
| | 44 |
| | 42 |
| | 46 |
|
Natural Gas (mmcfd) | | | | | | | |
Equatorial Guinea | 365 |
| | 446 |
| | 390 |
| | 441 |
|
United Kingdom(a) | 31 |
| | 28 |
| | 32 |
| | 29 |
|
Libya | — |
| | — |
| | — |
| | 1 |
|
Total Natural Gas | 396 |
| | 474 |
| | 422 |
| | 471 |
|
Equivalent Barrels (mboed) | | | | | | | |
Equatorial Guinea | 89 |
| | 105 |
| | 93 |
| | 107 |
|
United Kingdom(a) | 19 |
| | 18 |
| | 19 |
| | 18 |
|
Total International E&P (mboed) | 108 |
| | 123 |
| | 112 |
| | 125 |
|
Net Sales Volumes of Equity Method Investees | | | | | | | |
LNG (mtd) | 4,991 |
| | 6,624 |
| | 5,629 |
| | 6,601 |
|
Methanol (mtd) | 673 |
| | 980 |
| | 778 |
| | 1,066 |
|
|
| | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
Net Sales Volumes | 2016 | | 2015 | | Increase (Decrease) | | 2016 | | 2015 | | Increase (Decrease) |
Equivalent Barrels (mboed) | | | | | | | | | | | |
Equatorial Guinea | 101 | | 89 | | 13% | | 93 | | 93 | | —% |
United Kingdom(a) | 19 | | 19 | | —% | | 15 | | 19 | | (21)% |
Total International E&P | 120 | | 108 | | 11% | | 108 | | 112 | | (4)% |
Equity Method Investees | | | | |
| | | | | | |
LNG (mtd) | 5,797 | | 4,991 | | 16% | | 5,060 | | 5,629 | | (10)% |
Methanol (mtd) | 1,303 | | 673 | | 94% | | 1,292 | | 778 | | 66% |
Condensate & LPG (boed) | 11,306 | | 8,586 | | 32% | | 10,757 | | 10,892 | | (1)% |
| |
(a) | Includes natural gas acquired for injection and subsequent resale of 75 mmcfd and 57 mmcfd for the second quarters of 2016 and 2015, and 2014,5 mmcfd and 9 mmcfd and 6 mmcfd for the first six months of 20152016 and 2014.2015. |
Equatorial Guinea – AverageSecond quarter 2016 net sales volumes were 89 mboed and 93 mboed inhigher compared to the secondsame quarter and first six months of 2015 compareddue to 105 mboed and 107 mboed in the same periods of 2014. Plannedlower planned turnaround and maintenance activities at the Alba field and EGE.G. LNG facilities reduced production rates during the second quarter of 2015.facilities. The Alba turnaround subsequently reduced salesfield compression project achieved first gas in July, which is expected to our equity method investees, Alba Plant LLC, EGHoldingsmaintain the production plateau for an additional two years and AMPCO. Additionally, there was a planned turnaround at AMPCO in the first quarter of 2015.extend field life up to eight years.
During the second quarter of 2015, the Alba C21 development well reached total depth and completion activities are underway. To date, well performance results are consistent with pre-drill estimates.
United Kingdom – Average net sales volumes were 19 mboed for each of the second quarter and first six months of 2015, relatively flat as compared to 18 mboed in the same periods of 2014. Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during the first and second quarters of 2015. This completed the last of the planned five-well Brae infill drilling program begun in 2014. In addition, as fullcompression was reinstated during the second quarter of 2015 at the non-operated Foinaven field, this contributed to improved reliability.
During the third quarter of 2015, planned maintenance activities are scheduled at the East Brae and non-operated Foinaven field.
Libya – We had no sales during the first six months of 2015 as2016 were lower due to repair activities at the Brae Alpha facility following a result ofprocess pipe failure in late 2015. Production was restored at the facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven field partially offset the Brae Alpha shut-in.
Libya – Due to continued civil unrest. In December 2014, Libya’sunrest, there were no liftings during the quarter, or any period presented. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the second quarter, the two National Oil Corporation reinstated force majeureCompanies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerableour Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.
International E&P--Exploration
Kurdistan Region of Iraq – On the Harir Block, testing was completed on the Mirawa-2 appraisal well during the second quarter of 2015. The well has been temporarily suspended as a potential future producer and the drilling rig has been de-mobilized. We hold a 45% operated working interest in the block.
Oil Sands Mining
Our net synthetic crude oil sales volumes were 2949 mbbld and 4454 mbbld in the second quarter and first six months of 20152016 compared to 4429 mbbld and 4544 mbbld in the same periods of 2014. Production declined2015. Sales volumes increased in thecomparison to second quarter and first six months of 2015 primarilywhich were adversely affected due to the planned turnarounds at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. Production was relatively flatThese sales volume increases were partially offset by a brief suspension of operations at both the Muskeg River and Jackpine mines in May 2016 in order to support emergency response efforts related to the Fort McMurray area wildfires in addition to the completion of planned maintenance activities at the Jackpine Mine and expansion upgrader that began in the first six monthsquarter 2016. Neither of 2015 compared to the same period in 2014mines sustained any damage as a result of the planned turnarounds and unplanned downtime during the second quarter of 2015 were mostly offset by higher production driven by improved mine reliability during the first quarter of 2015.wildfires. We hold a 20% non-operated working interest in the AOSP.Athabasca Oil Sands Project.
Market Conditions
Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were significantly lower in the second quarter and first six months of 20152016 as compared to the same periodsperiod in 2014;2015; as a result, we experienced significant declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
North America E&P
The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the second quarter and first six months of 20152016 and 2014.2015.
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Average Price Realizations (a) | | | | | | | |
Crude Oil and Condensate (per bbl) (b) | | | | | | | |
Bakken |
| $51.36 |
| |
| $93.08 |
| |
| $45.84 |
| |
| $91.43 |
|
Eagle Ford | 53.47 |
| | 99.08 |
| | 47.81 |
| | 97.65 |
|
Oklahoma Resource Basins | 51.00 |
| | 101.12 |
| | 48.34 |
| | 98.05 |
|
Other North America (c) | 52.83 |
| | 93.45 |
| | 47.10 |
| | 91.40 |
|
Total Crude Oil and Condensate | 52.63 |
| | 95.95 |
| | 47.11 |
| | 94.30 |
|
Natural Gas Liquids (per bbl) | | | | | | | |
Bakken |
| $11.63 |
| |
| $45.13 |
| |
| $7.19 |
| |
| $51.04 |
|
Eagle Ford | 14.08 |
| | 30.20 |
| | 13.90 |
| | 33.76 |
|
Oklahoma Resource Basins | 14.45 |
| | 33.04 |
| | 15.83 |
| | 38.21 |
|
Other North America (c) | 25.65 |
| | 54.13 |
| | 26.03 |
| | 57.65 |
|
Total Natural Gas Liquids | 14.77 |
| | 34.80 |
| | 14.60 |
| | 38.75 |
|
Total Liquid Hydrocarbons (per bbl) | | | | | | | |
Bakken |
| $49.29 |
| |
| $90.47 |
| |
| $43.72 |
| |
| $89.16 |
|
Eagle Ford | 44.05 |
| | 85.36 |
| | 40.01 |
| | 84.78 |
|
Oklahoma Resource Basins | 30.29 |
| | 52.00 |
| | 29.24 |
| | 55.04 |
|
Other North America (c) | 50.89 |
| | 90.45 |
| | 45.52 |
| | 88.97 |
|
Total Liquid Hydrocarbons | 45.96 |
| | 86.43 |
| | 41.37 |
| | 85.65 |
|
Natural Gas (per mcf) | | | | | | | |
Bakken |
| $2.62 |
| |
| $4.12 |
| |
| $2.76 |
| |
| $6.14 |
|
Eagle Ford | 2.71 |
| | 4.76 |
| | 2.79 |
| | 4.83 |
|
Oklahoma Resource Basins | 2.64 |
| | 4.57 |
| | 2.63 |
| | 5.01 |
|
Other North America (c) | 2.98 |
| | 5.65 |
| | 3.29 |
| | 5.35 |
|
Total Natural Gas | 2.76 |
| | 5.00 |
| | 2.88 |
| | 5.14 |
|
Benchmarks | | | | | | | |
WTI crude oil (per bbl)(d) |
| $57.95 |
| |
| $102.99 |
| |
| $53.34 |
| |
| $100.84 |
|
Louisiana Light Sweet ("LLS") crude oil (per bbl)(e) | 62.94 |
| | 105.55 |
| | 57.97 |
| | 104.97 |
|
Mont Belvieu NGLs (per bbl) (f) | 17.65 |
| | 34.54 |
| | 18.02 |
| | 36.42 |
|
Henry Hub natural gas(g) (per mmbtu)(h) | 2.64 |
| | 4.67 |
| | 2.81 |
| | 4.80 |
|
|
| | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | Decrease | | 2016 | | 2015 | | Increase (Decrease) |
Average Price Realizations (a) | | | | | | | | | | | |
Crude Oil and Condensate (per bbl) (b) | $40.77 | | $52.63 | | (23)% | | $34.21 | | $47.11 | | (27 | )% |
Natural Gas Liquids (per bbl) | 14.84 | | 14.77 | | —% | | 11.43 |
| | 14.60 |
| | (22 | )% |
Total Liquid Hydrocarbons (per bbl) | 35.07 | | 45.96 | | (24)% | | 29.32 |
| | 41.37 |
| | (29 | )% |
Natural Gas (per mcf) | 1.96 | | 2.76 | | (29)% | | 1.99 |
| | 2.88 |
| | (31 | )% |
Benchmarks | | | | | | | | | | | |
WTI crude oil (per bbl) | $45.64 | | $57.95 | | (21)% | |
| $39.78 |
| |
| $53.34 |
| | (25 | )% |
LLS crude oil (per bbl) | 47.35 | | 62.94 | | (25)% | | 41.49 |
| | 57.97 |
| | (28 | )% |
Mont Belvieu NGLs (per bbl) (c) | 17.52 | | 17.65 | | (1)% | | 15.78 |
| | 18.02 |
| | (12 | )% |
Henry Hub natural gas (per mmbtu) | 1.95 | | 2.64 | | (26)% | | 2.02 |
| | 2.81 |
| | (28 | )% |
| |
(a) | Excludes gains or losses on commodity derivative instruments. |
| |
(b) | Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realizationrealizations by $0.12 per bbl and $0.06 per bbl for the second quarter 2016 and 2015, and $0.91 per bbl and $0.14 per bbl for the first six months of 2016 and 2015. Inclusion of realized gains on natural gas derivative instruments would have increased average realizations by $0.02 per mcf and $0.01 per mcf for the second quarter and first six months of 2015. There were no crude oil derivative instruments in 2014.2016. |
| |
(c) | Includes Gulf of Mexico and other conventional onshore U.S. production. |
| |
(e)
| Bloomberg Finance LLP: LLS St. James. |
| |
(f)
| Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline. |
| |
(g)
| Settlement date average. |
| |
(h)
| Million British thermal units. |
Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.
Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.
Natural gas – A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.
International E&P
The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the second quarter and first six months of 20152016 and 20142015.
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Average Price Realizations | | | | | | | |
Crude Oil and Condensate (per bbl) | | | | | | | |
Equatorial Guinea |
| $52.27 |
| |
| $90.91 |
| |
| $47.55 |
| |
| $90.66 |
|
United Kingdom | 62.97 |
| | 111.76 |
| | 60.19 |
| | 111.38 |
|
Total Crude Oil and Condensate | 56.70 |
| | 99.36 |
| | 52.92 |
| | 98.51 |
|
Natural Gas Liquids (per bbl) | | | | | | | |
Equatorial Guinea (a) |
| $1.00 |
| |
| $1.00 |
| |
| $1.00 |
| |
| $1.00 |
|
United Kingdom | 36.49 |
| | 64.37 |
| | 34.82 |
| | 69.56 |
|
Total Natural Gas Liquids | 3.10 |
| | 3.02 |
| | 3.29 |
| | 3.64 |
|
Total Liquid Hydrocarbons (per bbl) | | | | | | | |
Equatorial Guinea |
| $35.74 |
| |
| $59.72 |
| |
| $31.81 |
| |
| $61.12 |
|
United Kingdom | 61.93 |
| | 110.51 |
| | 58.96 |
| | 110.02 |
|
Total Liquid Hydrocarbons | 44.70 |
| | 75.41 |
| | 41.06 |
| | 75.48 |
|
Natural Gas (per mcf) | | | | | | | |
Equatorial Guinea (a) |
| $0.24 |
| |
| $0.24 |
| |
| $0.24 |
| |
| $0.24 |
|
United Kingdom | 6.98 |
| | 8.04 |
| | 7.34 |
| | 9.07 |
|
Libya | — |
| | — |
| | — |
| | 5.45 |
|
Total Natural Gas | 0.78 |
| | 0.69 |
| | 0.78 |
| | 0.80 |
|
Benchmark | | | | | | | |
Brent (Europe) crude oil (per bbl)(b) |
| $61.69 |
| |
| $109.70 |
| |
| $57.81 |
| |
| $108.93 |
|
|
| | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2016 | | 2015 | | Increase (Decrease) | | 2016 | | 2015 | | Increase (Decrease) |
Average Price Realizations | | | | | | | | | | | |
Crude Oil and Condensate (per bbl) | $42.21 | | $56.70 | | (26)% | | $37.56 | | $52.92 | | (29 | )% |
Natural Gas Liquids (per bbl) | 2.65 | | 3.10 | | (15)% | | 2.45 |
| | 3.29 |
| | (26 | )% |
Liquid Hydrocarbons (per bbl) | 32.11 | | 44.70 | | (28)% | | 28.11 |
| | 41.06 |
| | (32 | )% |
Natural Gas (per mcf) | 0.53 | | 0.78 | | (32)% | | 0.56 |
| | 0.78 |
| | (28 | )% |
Benchmark | | | | |
| | | | | |
|
|
Brent (Europe) crude oil (per bbl) (a) | $45.52 | | $61.69 | | (26%) | |
| $39.61 |
| |
| $57.81 |
| | (31 | )% |
| |
(a) | Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment. |
| |
(b)
| Average of monthly prices obtained from Energy Information Administration ("EIA")EIA website. |
Liquid hydrocarbons – Our United Kingdom ("U.K.") liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial GuineaE.G. is condensate, which receives lower prices than crude oil.
NGLs
Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are subjectsold to our equity method investees under fixed-price, term contracts; therefore, our reported average NGL realized prices within the International E&P segmentfor NGLs and natural gas will not fully track market price movements.
Natural gas –Our The equity affiliates then utilize, process and sell the NGLs at market prices and natural gas salesat fixed prices under long-term contracts, with our share of their income/loss reflected in the income from E.G. are subject to fixed-price, term contracts, making realized prices in this area less volatile; therefore, our reported average natural gas realized prices withinequity method investments line on the International E&P segment will not fully track market price movements.consolidated statements of income.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS").WCS.
The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices.
The following table presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for the second quarter and first six months of 20152016 and 20142015.
| | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | Decrease | | 2016 | | 2015 | | Increase (Decrease) |
Average Price Realizations | | | | | | | | | | | | | |
Synthetic Crude Oil (per bbl) |
| $52.46 |
| |
| $94.17 |
| |
| $44.33 |
| |
| $91.27 |
| $40.88 | | $52.46 | | (22%) | |
| $32.94 |
| |
| $44.33 |
| | (26 | %) |
Benchmark | | | | | | | | |
Benchmarks | | | | | | | |
WTI crude oil (per bbl)(a) |
| $57.95 |
| |
| $102.99 |
| |
| $53.34 |
| |
| $100.84 |
| $45.64 | | $57.95 | | (21%) | |
| $39.78 |
| |
| $53.34 |
| | (25 | %) |
WCS crude oil (per bbl)(b) |
| $46.35 |
| |
| $82.95 |
| |
| $40.13 |
| |
| $79.25 |
| |
AECO natural gas sales index (per mmbtu)(c) |
| $2.05 |
| |
| $4.46 |
| |
| $2.07 |
| |
| $4.72 |
| |
WCS crude oil (per bbl)(a) | | 32.29 | | 46.35 | | (30%) | | 25.75 |
| | 40.13 |
| | (36 | %) |
| |
(b)
| Monthly pricing based upon average WTI adjusted for differentials unique to western Canada. |
Results of Operations
Three Months Ended June 30, 2016 vs. Three Months Ended June 30, 2015
Sales and other operating revenues, including related party are presented by segment in the table below:
|
| | | | | | | |
| Three Months Ended June 30, |
(In millions) | 2016 | | 2015 |
Sales and other operating revenues, including related party | | | |
North America E&P | $ | 617 |
| | $ | 993 |
|
International E&P | 159 |
| | 211 |
|
Oil Sands Mining | 185 |
| | 147 |
|
Segment sales and other operating revenues, including related party | $ | 961 |
| | $ | 1,351 |
|
Unrealized (loss) gain on commodity derivative instruments | (91 | ) | | (44 | ) |
Sales and other operating revenues, including related party | $ | 870 |
| | $ | 1,307 |
|
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, 2015 | | Price Realizations | | Net Sales Volumes | | June 30, 2016 |
North America E&P Price-Volume Analysis (a) |
Liquid hydrocarbons | | $ | 893 |
| | $ | (172 | ) | | $ | (170 | ) | | $ | 551 |
|
Natural gas | | 90 |
| | (22 | ) | | (13 | ) | | 55 |
|
Realized gain on commodity | | | | | | | | |
derivative instruments | | 1 |
| | 2 |
| |
|
| | 3 |
|
Other sales | | 9 |
| |
|
| |
|
| | 8 |
|
Total | | $ | 993 |
| | | | | | $ | 617 |
|
International E&P Price-Volume Analysis |
Liquid hydrocarbons | | $ | 172 |
| | $ | (50 | ) | | $ | 7 |
| | $ | 129 |
|
Natural gas | | 28 |
| | (10 | ) | | 4 |
| | 22 |
|
Other sales | | 11 |
| | | | | | 8 |
|
Total | | $ | 211 |
| | | | | | $ | 159 |
|
Oil Sands Mining Price-Volume Analysis |
Synthetic crude oil | | $ | 137 |
| | $ | (51 | ) | | $ | 95 |
| | $ | 181 |
|
Other sales | | 10 |
| |
|
| |
|
| | 4 |
|
Total | | $ | 147 |
| | | | | | $ | 185 |
|
| |
(c)(a)
| Monthly average AECO day ahead index.Three months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production. |
Marketing revenues decreased $94 million in the second quarter of 2016 from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America E&P and OSM, which were further compounded by a lower commodity price environment.
Income from equity method investmentsincreased $11 million in the second quarter of 2016 from the comparable 2015 period. The increase is primarily due to an increase in net sales volumes as 2015 volumes were lower because of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities.
Net gain on disposal of assets in the second quarter of 2016 was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the consolidated financial statements for information about dispositions.
Production expenses decreased $100 million. North America E&P declined $50 million primarily due to lower operational, maintenance and labor costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $8 million primarily as a result of lower project and labor costs in the U.K. and 2015 also includes costs arising from planned flowline maintenance at the outside operated Foinaven field; these declines were partially offset by increased costs resulting from higher net sales volumes. OSM
decreased $42 million primarily due to lower turnaround costs andcontinued cost management, specifically staffing and contract labor.
The second quarter of 2016 production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to an increase in volumes, combined with reduced maintenance and project costs in the U.K. The OSM expense rate decreased as a result of higher sales volumes and lower production expenses, as discussed above.
The following table provides production expense rates for each segment: |
| | | | | | | |
| Three Months Ended June 30, |
($ per boe) | 2016 | | 2015 |
Production Expense Rate | | | |
North America E&P |
| $6.28 |
| |
| $7.19 |
|
International E&P |
| $5.09 |
| |
| $6.51 |
|
Oil Sands Mining (a) |
| $39.02 |
| |
| $78.24 |
|
| |
(a) | Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income. |
Marketing costs decreased $94 million in the second quarter of 2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.
Exploration expensesincreased $78 million primarily as a result of our decision to not 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) | 2016 | | 2015 |
Exploration Expenses | | | |
Unproved property impairments | $ | 133 |
| | $ | 40 |
|
Dry well costs | 22 |
| | 41 |
|
Geological and geophysical | — |
| | 12 |
|
Other | 34 |
| | 18 |
|
Total exploration expenses | $ | 189 |
| | $ | 111 |
|
Depreciation, depletion and amortizationdecreased $190 million primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford in the second half of 2015 and as a result of the non-core asset dispositions in 2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015. The DD&A rate for International E&P declined due to lower asset retirement costs, with cost estimates refined in the fourth quarter of 2015. The DD&A rate for OSM declined as a result of a higher proved reserve base in the fourth quarter of 2015.
|
| | | | | | | |
| Three Months Ended June 30, |
($ per boe) | 2016 | | 2015 |
DD&A Rate | | | |
North America E&P |
| $21.16 |
| |
| $25.45 |
|
International E&P |
| $6.22 |
| |
| $7.17 |
|
Oil Sands Mining |
| $11.39 |
| |
| $12.87 |
|
Impairments decreased $44 million in the second quarter of 2016 as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note 13 to the consolidated financial statements for discussion of the impairment.
Taxes other than incomeinclude production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes, decreased $39 million in the second quarter of 2016. The following table summarizes the components of taxes other than income:
|
| | | | | | | |
| Three Months Ended June 30, |
(In millions) | 2016 | | 2015 |
Production and severance | $ | 25 |
| | $ | 40 |
|
Ad valorem | 5 |
| | 15 |
|
Other | 9 |
| | 23 |
|
Total | $ | 39 |
| | $ | 78 |
|
General and administrative expensesdecreased $36 million primarily due to lower pension settlement charges in the second quarter of 2016, which totaled $31 million, compared to $64 million in the prior year.
Net interest and other increased $28 million primarily due to increased interest expense associated with our June 2015 debt issuance. See Note 16 to the consolidated financial statements for discussion of the June 2015 debt issuance.
Provision (benefit) for income taxes reflects an effective tax rate of 29% in the second quarter of 2016, as compared to 2% in the second quarter of 2015.
Segment Income(Loss)
Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss): |
| | | | | | | |
| Three Months Ended June 30, |
(In millions) | 2016 | | 2015 |
North America E&P | $ | (70 | ) | | $ | (45 | ) |
International E&P | 55 |
| | 41 |
|
Oil Sands Mining | (38 | ) | | (77 | ) |
Segment income (loss) | (53 | ) | | (81 | ) |
Items not allocated to segments, net of income taxes | (117 | ) | | (305 | ) |
Net income (loss) | $ | (170 | ) | | $ | (386 | ) |
North America E&P segment loss increased $25 million after-tax primarily due to lower price realizations and sales volumes, which was partially offset by the impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.
International E&P segment incomeincreased $14 million after-tax primarily due to decreased exploration expenses and an increase in income from equity investments, which were partially offset by lower price realizations.
Oil Sands Mining segment loss decreased $39 million after-tax primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations and higher DD&A expense.
Results of Operations
Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015
Consolidated Results of Operation
Sales and other operating revenues, including related party are presented by segment in the table below:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 |
Sales and other operating revenues, including related party | | | | | | | | | | |
North America E&P | $ | 993 |
| | $ | 1,540 |
| | $ | 1,843 |
| | $ | 2,932 |
| $ | 1,110 |
| | $ | 1,843 |
|
International E&P | 211 |
| | 347 |
| | 393 |
| | 727 |
| 255 |
| | 393 |
|
Oil Sands Mining | 147 |
| | 383 |
| | 372 |
| | 760 |
| 333 |
| | 372 |
|
Segment sales and other operating revenues, including related party | $ | 1,351 |
| | $ | 2,270 |
| | $ | 2,608 |
| | $ | 4,419 |
| $ | 1,698 |
| | $ | 2,608 |
|
Unrealized loss on crude oil derivative instruments | (44 | ) | | — |
| | (21 | ) | | — |
| |
Unrealized loss on commodity derivative instruments | | (114 | ) | | (21 | ) |
Sales and other operating revenues, including related party | $ | 1,307 |
| | $ | 2,270 |
| | $ | 2,587 |
| | $ | 4,419 |
| $ | 1,584 |
| | $ | 2,587 |
|
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 | | Six Months Ended | | Increase (Decrease) Related to | | Six Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 | | June 30, 2015 | | Price Realizations | | Net Sales Volumes | | June 30, 2016 |
North America E&P Price-Volume Analysis(a) | Liquid hydrocarbons | | $ | 1,403 |
| | $ | (786 | ) | | $ | 276 |
| | $ | 893 |
| | $ | 1,633 |
| | $ | (394 | ) | | $ | (279 | ) | | $ | 960 |
|
Natural gas | | 133 |
| | (73 | ) | | 30 |
| | 90 |
| | 188 |
| | (51 | ) | | (24 | ) | | 113 |
|
Realized gain on crude oil | | | | | | | | | |
Realized gain on commodity | | | | | | | | | |
derivative instruments | | — |
| | 1 |
| |
|
| | 1 |
| | 5 |
| | 19 |
| | | | 24 |
|
Other sales | | 4 |
| |
|
| |
|
| | 9 |
| | 17 |
| | | | | | 13 |
|
Total | | $ | 1,540 |
| | | | | | $ | 993 |
| | $ | 1,843 |
| | | | | | $ | 1,110 |
|
International E&P Price-Volume Analysis | | International E&P Price-Volume Analysis |
Crude oil and condensate | | | | | | | | | |
Natural gas liquids | | | | | | | | | |
Liquid hydrocarbons | | | $ | 310 |
| | $ | (90 | ) | | $ | (26 | ) | | $ | 194 |
|
Natural gas | | | 60 |
| | (17 | ) | | — |
| | 43 |
|
Other sales | | | 23 |
| | | | | | 18 |
|
Total | | | $ | 393 |
| | | | | | $ | 255 |
|
Oil Sands Mining Price-Volume Analysis | | Oil Sands Mining Price-Volume Analysis |
Synthetic crude oil | | | $ | 355 |
| | $ | (112 | ) | | $ | 81 |
| | $ | 324 |
|
Other sales | | | 17 |
| | | | | | 9 |
|
Total | | | $ | 372 |
| | | | | | $ | 333 |
|
|
| | | | | | | | | | | | | | | | |
| | Six Months Ended | | Increase (Decrease) Related to | | Six Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 |
North America E&P Price-Volume Analysis |
Liquid hydrocarbons | | $ | 2,647 |
| | $ | (1,748 | ) | | $ | 734 |
| | $ | 1,633 |
|
Natural gas | | 276 |
| | (147 | ) | | 59 |
| | 188 |
|
Realized gain on crude oil | | | | | | | | |
derivative instruments | | — |
| | 5 |
| | | | 5 |
|
Other sales | | 9 |
| | | | | | 17 |
|
Total | | $ | 2,932 |
| | | | | | $ | 1,843 |
|
International E&P
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Increase (Decrease) Related to | | Three Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 |
International E&P Price-Volume Analysis |
Liquid hydrocarbons | | $ | 305 |
| | $ | (118 | ) | | $ | (15 | ) | | $ | 172 |
|
Natural gas | | 30 |
| | 3 |
| | (5 | ) | | 28 |
|
Other sales | | 12 |
| | | | | | 11 |
|
Total | | $ | 347 |
| | | | | | $ | 211 |
|
|
| | | | | | | | | | | | | | | | |
| | Six Months Ended | | Increase (Decrease) Related to | | Six Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 |
International E&P Price-Volume Analysis |
Liquid hydrocarbons | | $ | 634 |
| | $ | (261 | ) | | $ | (63 | ) | | $ | 310 |
|
Natural gas | | 69 |
| | (2 | ) | | (7 | ) | | 60 |
|
Other sales | | 24 |
| | | | | | 23 |
|
Total | | $ | 727 |
| | | | | | $ | 393 |
|
Oil Sands Mining
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended | | Increase (Decrease) Related to | | Three Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 |
Oil Sands Mining Price-Volume Analysis |
Synthetic crude oil | | $ | 377 |
| | $ | (110 | ) | | $ | (130 | ) | | $ | 137 |
|
Other sales | | 6 |
| |
|
| |
|
| | 10 |
|
Total | | $ | 383 |
| | | | | | $ | 147 |
|
|
| | | | | | | | | | | | | | | | |
| | Six Months Ended | | Increase (Decrease) Related to | | Six Months Ended |
(In millions) | | June 30, 2014 | | Price Realizations | | Net Sales Volumes | | June 30, 2015 |
Oil Sands Mining Price-Volume Analysis |
Synthetic crude oil | | $ | 750 |
| | $ | (376 | ) | | $ | (19 | ) | | $ | 355 |
|
Other sales | | 10 |
| | | | | | 17 |
|
Total | | $ | 760 |
| | | | | | $ | 372 |
|
(a) Six months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.Marketing revenues decreased $435 million and $772 million infor the second quarter and first six months of 2015 from the comparable prior-year periods.2016 decreased by $240 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. Because the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases aredecrease is related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.
Income from equity method investments decreased $94 million and $195 million in the second quarter and first six months of 2015 from the comparable 2014 period.$11 million. The decrease in the second quarter of 2015 is primarily due to lower price realizations for Liquified Natural Gas ("LNG") at our LNG facility, Liquified Petroleum Gas ("LPG") at our Alba plant, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to the decrease in 2015 were lowernet sales volumes due toas a result of planned downtime at E.G. as a result of the previously mentionedAlba field compression project which impacted our equity method plants, which was partially offset by planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and E.G. LNG facilities in 2015. Also impacting the LNG facility.first six months of 2016 were lower price realizations for LPG at our Alba plant.
Net gain on disposal of assets for the first six months of 2016 was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the consolidated financial statements for information about dispositions.
Production expenses for the first six months of 2016 decreased $112by $216 million in the second quarter of 2015 compared to the second quartersame period of 2014.2015. North America E&P declined $38$118 million due to lower operational, maintenance and labor costs.costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $35$22 million primarily because of lower costs relatedlargely due to lower sales volumes, while the second quarter of 2014 included $5 million of turnaroundoperational costs at Brae and subsea maintenance costs at the non-operated Foinaven field in the U.K. OSM decreased $39$76 million primarily due to lower feedstock purchases (due to planned turnarounds and unplanned downtime as previously discussed) and continued cost management, especiallyspecifically staffing and contract labor. Also contributing to the OSM decrease waslabor, lower turnaround costs, and a more favorable exchange rate on expenses denominated in the Canadian Dollar. These declines were partially offset by costs incurred from the turnaround.
Production expenses for theThe first six months of 2015 decreased by $210 million compared to the same period of 2014. North America E&P declined $47 million due to lower operational, maintenance and labor costs. International E&P declined
$68 million due to lower repair, maintenance and turnaround costs as well as lower production volumes. The previous six month period included $11 million of non-recurring riser repair costs in E.G., $5 million of expenses from a Brae turnaround and costs related to reliability issues and subsea maintenance at the non-operated Foinaven field in the U.K. OSM decreased $95 million due to the same reasons as described in the preceding paragraph.
The second quarter of 20152016 production expense rate (expense per boe) for North America E&P declined relative to the same quarter in 2014primarily due to overall cost reductions as previously discussed, and leveraging efficiencies asthat occurred at a rate faster than our production volumes increased. The expense rate for International E&P declined due to reduced maintenance and project costs in second quarter of 2015 as compared to 2014. The OSM expense rate increased due to the turnarounds and unplanned downtime in the second quarter of 2015, which resulted in lower sales volumes and higher costs.
The expense rate during the first six months of 2015 compared the same period in 2014 decreased for North America E&P due to overall cost reductions as discussed in the preceding paragraph.decline. The International E&P expense rate decreased in the first six months of 20152016 primarily due to lowerreduced maintenance and project costs as discussed in the preceding paragraphs.U.K. The OSM expense rate remained relatively flatdecreased in the first six months of 2015 as the2016 primarily due to higher production coupled with lower feedstock purchases, cost management and a favorable exchange rate were offset by the aforementioned higher turnaroundoperational costs. The following table provides production expense rates for each segment:
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Six Months Ended June 30, |
($ per boe) | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 |
Production Expense Rate | | | | | | | | | | | |
North America E&P |
| $7.19 |
| |
| $10.47 |
| |
| $7.57 |
| |
| $10.74 |
| |
| $6.22 |
| |
| $7.57 |
|
International E&P |
| $6.51 |
| |
| $8.87 |
| |
| $6.45 |
| |
| $8.82 |
| |
| $5.53 |
| |
| $6.45 |
|
Oil Sands Mining (a) |
| $78.24 |
| |
| $51.53 |
| |
| $50.06 |
| |
| $49.54 |
| |
| $33.42 |
| |
| $50.06 |
|
| |
(a) | Production expense per synthetic crude oil barrel includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs. |
Marketing costs decreased $432 million and $769$241 million in the second quarter and first six months of 20152016 from the comparable 2014 periods,2015 period, consistent with the marketing revenues changes discussed above.
Exploration expenses declined $34were $12 million in the second quarter of 2015 compared to the second quarter of 2014 due to lower unproved property impairments and dry well costs. Unproved property impairments declined primarily as a result of fewer Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. The second quarter of 2014 included dry well costs associated with our exploration programs in Kurdistan, Ethiopia and Kenya. Included in the dry well costs for the second quarter of 2015 is $38 million of previously suspended well costs that were written off. The well costs are associated with our Canadian in-situ assets at Birchwood. See Note 11 to the consolidated financial statements for further discussion.
Exploration expenses were $17 million lowerhigher in the first six months of 20152016 than in the comparable 20142015 period primarily due to lowerhigher unproved property impairments, which were partially offset by higherlower dry well costs. Unproved property impairments were higher in 20142016 primarily as a result of Eagle Ford and BakkenGulf of Mexico leases that either expired or that we decided not to drill or extend.drill. Dry well costs increased for the first six months of 2015 due toprimarily consist of costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and the aforementioned suspended well costs related to Birchwood in-situ. Dry well costs for the first six months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya. The following table summarizes the components of exploration expenses:
| | | Three Months Ended | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 |
Exploration Expenses | | | | | | | | | | |
Unproved property impairments | $ | 40 |
| | $ | 60 |
| | $ | 49 |
| | $ | 101 |
| $ | 144 |
| | $ | 49 |
|
Dry well costs | 41 |
| | 53 |
| | 99 |
| | 55 |
| 22 |
| | 99 |
|
Geological and geophysical | 12 |
| | 6 |
| | 15 |
| | 17 |
| — |
| | 15 |
|
Other | 18 |
| | 26 |
| | 38 |
| | 45 |
| 47 |
| | 38 |
|
Total exploration expenses | $ | 111 |
| | $ | 145 |
| | $ | 201 |
| | $ | 218 |
| $ | 213 |
| | $ | 201 |
|
Depreciation, depletion and amortization (“DD&A”) increased $71 million and $249decreased $402 million in the second quarter and first six months of 20152016 from the comparable 2014 periods2015 period primarily as a result of production volume decreases and a higher North America E&P net sales volumes from our three U.S. resource plays, partially offset by lower International E&P sales volumes. OSM net sales volumes also declinedproved reserve base in Eagle Ford in the second quarterhalf of 2015, as previously discussed, also contributing to that quarter's decrease.2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015.
| | | Three Months Ended | | Six Months Ended June 30, | Six Months Ended June 30, |
($ per boe) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 |
DD&A Rate | | | | | |
| | |
| |
| | |
|
North America E&P |
| $25.45 |
| |
| $26.58 |
| |
| $26.16 |
| |
| $26.72 |
|
| $21.79 |
| |
| $26.16 |
|
International E&P |
| $7.17 |
| |
| $6.64 |
| |
| $6.62 |
| |
| $6.45 |
|
| $5.98 |
| |
| $6.62 |
|
Oil Sands Mining |
| $12.87 |
| |
| $11.78 |
| |
| $12.58 |
| |
| $11.74 |
|
| $11.34 |
| |
| $12.58 |
|
Impairments are discusseddecreased $43 million in the first six months of 2016 as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note 1213 to the consolidated financial statements.statements for discussion of the impairment.
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than incomevolumes, decreased $31 million and $59$58 million in the second quarter and first six months of 20152016 from the comparable 2014 periods. This decrease was partially offset by an increase in sales volumes in North America E&P.2015 period. The following table summarizes the components of taxes other than income:
| | | Three Months Ended | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 |
Production and severance | $ | 40 |
| | $ | 68 |
| | $ | 74 |
| | $ | 122 |
| $ | 44 |
| | $ | 74 |
|
Ad valorem | 15 |
| | 19 |
| | 31 |
| | 38 |
| 19 |
| | 31 |
|
Other | 23 |
| | 22 |
| | 40 |
| | 44 |
| 24 |
| | 40 |
|
Total | $ | 78 |
| | $ | 109 |
| | $ | 145 |
| | $ | 204 |
| $ | 87 |
| | $ | 145 |
|
General and administrative expenses increased $29 million in the second quarter of 2015 compared to the same period in 2014 primarily due to higher pension settlement charges. Settlement charges in the second quarter of 2015 totaled $64 million, compared to settlement charges of $8 million in the prior year quarter. This increase in pension settlement costs was partially offset by costs savings realized from the workforce reductions that occurred in the first quarter of 2015.
General and administrative expenses increased $13decreased $56 million in the first six months of 20152016 compared to the same period in 2014.2015. This increasedecrease was primarily due to $43 million of severance related expenses in the first quarter of 2015 and $10 million of increased pension settlement expense (first six months of 2015 totaled $81 million as compared to $71 million for the previous year). These increased costs were partially offset by costscost savings realized in the second quarter of 2015 resulting from the 2015 workforce reductions.reductions and corresponding severance expenses.
Provision (benefit) for income taxes reflect effective tax rates of 2% and 18%37% in the second quarter and first six months of 2015,2016, as compared to 30% and 32%18% from the comparable 2014 periods. The effective rates for 2015 reflect $135 million of non-cash additional deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada.period. See Note 89 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations presented in 2014 are net of tax. See Note 5 to the consolidated financial statements for financial information about discontinued operations.
Segment Income (Loss)
Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
| | | Three Months Ended | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 |
North America E&P | $ | (45 | ) | | $ | 302 |
| | $ | (206 | ) | | $ | 544 |
| $ | (265 | ) | | $ | (206 | ) |
International E&P | 41 |
| | 160 |
| | 64 |
| | 381 |
| 59 |
| | 64 |
|
Oil Sands Mining | (77 | ) | | 55 |
| | (96 | ) | | 119 |
| (86 | ) | | (96 | ) |
Segment income (loss) | (81 | ) | | 517 |
| | (238 | ) | | 1,044 |
| (292 | ) | | (238 | ) |
Items not allocated to segments, net of income taxes | (305 | ) | | (157 | ) | | (424 | ) | | (286 | ) | (285 | ) | | (424 | ) |
Income (loss) from continuing operations | (386 | ) | | 360 |
| | (662 | ) | | 758 |
| |
Discontinued operations (a) | — |
| | 180 |
| | — |
| | 931 |
| |
Net income (loss) | $ | (386 | ) | | $ | 540 |
| | $ | (662 | ) | | $ | 1,689 |
| $ | (577 | ) | | $ | (662 | ) |
| |
(a)
| As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014. |
North America E&P segment income (loss)loss decreased $347 million and $750increased $59 million after-tax in the second quarter and first six months of 20152016 from the comparable 2014 periods. The decrease is2015 period primarily due to lower price realizations and sales volumes, which was partially offset by the impacts from the increasedimpact of lower net sales volumes from the U.S. resource plays.to DD&A, production costs and taxes other than income; and lower exploration expenses.
International E&P segment income decreased $119 million and $317$5 million after-tax in the second quarter and first six months of 20152016 from the comparable 2014 periods. The decreases are2015 period primarily due to lower liquid hydrocarbon price realizations and net sales volumes, as well as reduced income from equity investments.realizations. These declines were partially offset by lower exploration, production and explorationDD&A expenses.
Oil Sands Mining segment income (loss)loss decreased $132 million and $215$10 million after-tax in the second quarter and first six months of 20152016 from the comparable 2014 periods2015 period primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations partially offset by reduced production expenses.and higher DD&A expense.
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 subsequent to Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 20142015, 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. We performed our annual impairment test in April 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Estimated Quantities of Net Reserves
Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first eight months of 2016:
|
| | |
| Unweighted 8-month 2016 Average | Unweighted 12-month 2015 Average |
WTI Crude oil | $40.48 | $50.28 |
Henry Hub natural gas | 2.24 | 2.59 |
Brent crude oil | 41.08 | 54.25 |
Natural gas liquids | 14.92 | 17.32 |
Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices decrease during the remainder of 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. Assuming lower commodity pricing in the remaining 4-months of 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.
Cash Flows and Liquidity
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
| | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | 2014 | 2016 | 2015 |
Sources of cash and cash equivalents | |
| |
| |
| |
|
Continuing operations | $ | 717 |
| $ | 2,118 |
| |
Discontinued operations | — |
| 440 |
| |
Operating activities | | $ | 252 |
| $ | 717 |
|
Disposals of assets | | 758 |
| 2 |
|
Borrowings | 1,996 |
| — |
| — |
| 1,996 |
|
Disposals of assets | 2 |
| 2,232 |
| |
Common stock issuance | | 1,236 |
| — |
|
Other | 43 |
| 113 |
| 39 |
| 43 |
|
Total sources of cash and cash equivalents | $ | 2,758 |
| $ | 4,903 |
| $ | 2,285 |
| $ | 2,758 |
|
Uses of cash and cash equivalents | | |
Cash additions to property, plant and equipment | $ | (2,320 | ) | $ | (2,230 | ) | $ | (753 | ) | $ | (2,320 | ) |
Investing activities of discontinued operations | — |
| (233 | ) | |
Deposit for acquisition | | (89 | ) | — |
|
Purchases of short-term investments | (925 | ) | — |
| — |
| (925 | ) |
Debt issuance costs | (19 | ) | — |
| — |
| (19 | ) |
Debt repayments | (34 | ) | (34 | ) | — |
| (34 | ) |
Dividends paid | (285 | ) | (260 | ) | (77 | ) | (285 | ) |
Purchases of common stock | — |
| (1,000 | ) | |
Commercial paper, net | — |
| (135 | ) | |
Other | (1 | ) | (10 | ) | (3 | ) | (1 | ) |
Cash held for sale | — |
| (96 | ) | |
Total uses of cash and cash equivalents | $ | (3,584 | ) | $ | (3,998 | ) | $ | (922 | ) | $ | (3,584 | ) |
Commodity prices began decliningCash flows generated from operating activities in the second half of 2014 and remain substantially lower through 2015 as compared to the first six months of 2014.2016 were lower as the downturn in the commodity cycle continued. This lowercontinued downward pressure on price trend adversely impacted our cash flows in 2015. Partially offsettingrealizations, coupled with the decline in prices were increasedlower net sales volumes, in the North America E&P segment. While we are unable to predict future commodity price movements, if this lower price environment continues it would continue to negatively impact our cash flows from operating activitiesactivities. In the first six months of 2016, consolidated average oil and NGL price realizations were down by approximately 27% and consolidated net sales volumes declined by 9% as compared to the previousprior year.
Borrowings reflectProceeds from disposals of assets are primarily from the sale of our Wyoming upstream and midstream assets; see Note 6 to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from the issuanceour public sale of senior notes in June 2015.common stock. See Liquidity and Capital Resources below for additional information.
Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposals of assets in the first six months of 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 5 to the consolidated financial statements.
Purchases of short-term investments were made from proceeds received from the senior notes issuance in June 2015. The investments consist of time deposits with maturity dates ranging from September - October 2015.
Additions to property, plant and equipment are our most significant use of cash and cash equivalents.equivalents and were lower in the first half of 2016 consistent with a reduced Capital Program as compared to the prior year. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash flows:flows (the table excludes an $89 million deposit paid into escrow related to the acquisition of PayRock assets - see Note 5 to the consolidated financial statements for further information related to this acquisition):
| | | Six Months Ended June 30, | Six Months Ended June 30, |
(In millions) | 2015 | | 2014 | 2016 | | 2015 |
North America E&P | $ | 1,484 |
| | $ | 1,969 |
| $ | 468 |
| | $ | 1,484 |
|
International E&P | 245 |
| | 220 |
| 44 |
| | 245 |
|
Oil Sands Mining | 37 |
| | 123 |
| 16 |
| | 37 |
|
Corporate | 14 |
| | 13 |
| 8 |
| | 14 |
|
Total capital expenditures | 1,780 |
| | 2,325 |
| 536 |
| | 1,780 |
|
(Increase) decrease in capital expenditure accrual | 540 |
| | (95 | ) | |
Decrease in capital expenditure accrual | | 217 |
| | 540 |
|
Total use of cash and cash equivalents for property, plant and equipment | $ | 2,320 |
| | $ | 2,230 |
| $ | 753 |
| | $ | 2,320 |
|
DuringThe Board of Directors approved a $0.05 per share dividend for the first six monthsquarter of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program, 13 million of2016, which were acquiredwas paid in the second quarter of 2014 at a cost of $449 million.2016. See Capital Requirements below for additional information about the second quarter dividend.
Liquidity and Capital Resources
On June 10, 2015,In March 2016, we issued $2 billion aggregate principal amount166,750,000 shares of unsecured senior notes which consistour common stock, par value $1 per share, at a price of the following series:
•$600 million of 2.70% senior notes due June 1, 2020
•$900 million of 3.85% senior notes due June 1, 2025
•$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We will use the aggregate$7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to repaystrengthen our $1 billion 0.90% senior notes due 2015, which mature on November 1, 2015,balance sheet and for general corporate purposes.purposes, including funding a portion of our Capital Program.
In May 2015,Also in March 2016, we amendedincreased our $2.5$3 billion unsecured revolving credit facility (as so amended, the "Credit Facility") to increase the facility sizeCredit Facility by $500$300 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.$3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.unaffected by the increase.
Our main sources of liquidity are cash and cash equivalents, short-term investments,sales of non-core assets, internally generated cash flow from operations, the issuance of notes,capital market transactions, and our $3$3.3 billion Credit Facility and sales of non-core assets.Facility. Our working capital requirements are supported by these sources and we may alsodraw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue commercial paper, which is backed bydebt or equity securities through the shelf registration statement discussed below as part of our revolving credit facility. Furthermore, we actively manage ourlonger-term liquidity and capital spending program, including the level and timing of activities associated with our drilling programs.management. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements for the foreseeable future, including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
OutlookDue to decreases in crude oil and U.S. natural gas prices, credit rating agencies reviewed companies in the industry earlier this year, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital, 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, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.
We expectThe June 23, 2016 referendum by British voters to exit the European Union (“Brexit”) provided uncertainty and potential volatility around European currencies, and resulted in a decline in the value of the British pound, as compared to the U.S. dollar and other currencies. Volatility in exchange rates may continue in the short term as the U.K. negotiates its exit from the European Union. A weaker British pound compared to the U.S. dollar during a reporting period causes local currency results of our capital, investment and exploration spending budget for full-year 2015U.K. operations to be at or below $3.3 billiontranslated into fewer U.S. dollars. For our U.K. operations a majority of our revenues are tied to global crude oil prices which are denominated in U.S. dollars while a significant portion of our operating and estimate full-year North America E&Pcapital costs are denominated in British pounds. In addition, our U.K. operations have an asset retirement obligation, which represents a future cash commitment. In the longer term, any impact from Brexit on our U.K. operations will depend, in part, on the outcome of tariff, trade, regulatory, and International E&P production volumes (excluding Libya) to be 375-390 net mboed.other negotiations.
Capital Resources
Credit Arrangements and Borrowings
At June 30, 2015,2016, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
At June 30, 2015,2016, we had $8.4$7.3 billion in long-term debt outstanding, with our next debt maturity in the amount of which approximately $1.0 billion matures$682 million due in the fourth quarter of 2015. 2017.
We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt securities.
CashAsset Disposals
During the quarter, we announced the sale of our Wyoming upstream and Short-Term Investments-Adjustedmidstream assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.
In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. We closed on certain of the asset sales during the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.
Cash-Adjusted Debt-To-Capital Ratio
Our cash and short-term investments-adjustedcash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash equivalents and short-term investments)equivalents) was 22%20% at June 30, 2015,2016, compared to 16%25% at December 31, 2014.2015.
| | | June 30, | | December 31, | June 30, | | December 31, |
(In millions) | 2015 | | 2014 | 2016 | | 2015 |
Long-term debt due within one year | $ | 1,035 |
| | $ | 1,068 |
| $ | 1 |
| | $ | 1 |
|
Long-term debt | 7,321 |
| | 5,323 |
| 7,280 |
| | 7,276 |
|
Total debt | $ | 8,356 |
| | $ | 6,391 |
| $ | 7,281 |
| | $ | 7,277 |
|
Cash and cash equivalents | $ | 1,572 |
| | $ | 2,398 |
| $ | 2,584 |
| | $ | 1,221 |
|
Short-term investments | $ | 925 |
| | $ | — |
| |
Equity | $ | 20,218 |
| | $ | 21,020 |
| $ | 19,153 |
| | $ | 18,553 |
|
Calculation: | |
| | |
| |
| | |
|
Total debt | $ | 8,356 |
| | $ | 6,391 |
| $ | 7,281 |
| | $ | 7,277 |
|
Minus cash and cash equivalents | 1,572 |
| | 2,398 |
| 2,584 |
| | 1,221 |
|
Minus short-term investments | 925 |
| | — |
| |
Total debt minus cash, cash equivalents and short-term investments | $ | 5,859 |
| | $ | 3,993 |
| |
Total debt minus cash, cash equivalents | | $ | 4,697 |
| | $ | 6,056 |
|
Total debt | $ | 8,356 |
| | $ | 6,391 |
| $ | 7,281 |
| | $ | 7,277 |
|
Plus equity | 20,218 |
| | 21,020 |
| 19,153 |
| | 18,553 |
|
Minus cash and cash equivalents | 1,572 |
| | 2,398 |
| 2,584 |
| | 1,221 |
|
Minus short-term investments | 925 |
| | — |
| |
Total debt plus equity minus cash, cash equivalents and short-term investments | $ | 26,077 |
| | $ | 25,013 |
| |
Cash and short-term investments-adjusted debt-to-capital ratio | 22 | % | | 16 | % | |
Total debt plus equity minus cash, cash equivalents | | $ | 23,850 |
| | $ | 24,609 |
|
Cash-adjusted debt-to-capital ratio | | 20 | % | | 25 | % |
Capital Requirements
As noted aboveWe closed on our purchase agreement of PayRock for $888 million, as discussed in "Outlook," weNote 5 to the consolidated financial statements. We expect our total capital, investment and exploration spending budgetCapital Program for full-year 20152016 to be at$1.3 billion, or below $3.3 billion.$100 million lower than the original budget, which includes the increased activity from the PayRock acquisition.
On July 29, 2015,27, 2016, our Board of Directors approved a dividend of $0.21$0.05 per share for the second quarter of 20152016 payable September 10, 201512, 2016 to stockholders of record at the close of business on August 19, 2015.17, 2016.
As of June 30, 2015,2016, we plan to make contributions of up to $42$34 million to our funded pension plans during the remainder of 2015.2016.
Contractual Cash Obligations
As of June 30, 2105,2016, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 20142015 Annual Report on Form 10-K, except for the agreement we entered into to acquire PayRock as described above, which was paid with cash on hand.
During the third quarter we executed an agreement to terminate our issuanceGulf of $2 billion aggregate principal amountMexico deepwater drilling rig contract, as a result we expect to make a termination payment of unsecured senior notes, as more fully described in Note 15.$113 million during the third quarter of 2016.
Environmental Matters and Other Contingencies
We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures asIn July 2015, we received a resultrequest for information from the EPA under Section 114 of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflectedthe Clean Air Act regarding several tank batteries used in our Bakken operations. Beginning in the pricessecond quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our products and services, ourdevelopment and/or operating results will be adversely affected.costs. We do not believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitorany penalties or corrective action expenditures that may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
There have been no significant changes to our environmental matters subsequent to December 31, 2014.
Other Contingencies
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedingsresult from this matter will not have a material adverse effect on our consolidated financial position, results of operationsoperation or cash flows.
Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact, included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding our operational, financial and growth strategies, our ability to effect those strategies and the expected timing and results thereof, planned capital expenditures and the impact thereof, future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, timingcapital plans, cost and expectations, maintenance activitiesexpense estimates, assets acquisitions and the timing and impact thereof, well spud timing and expectations, our financial and operational outlook and ability to fulfill that outlook, oursales, future financial position, liquidity and capital resources, our 2015 budget and planned allocation, and theother plans and objectives of our management for our future operations. In addition, manyoperations, are forward-looking statements may be identified by the use of forward-looking terminologystatements. Words such as “anticipate,” “believe,” "could," “estimate,” “expect,” “target,“forecast,” "guidance," "intend," "may," “plan,” “project,” “could,” “may,“seek,” “should,” "target," "will," “would” or similar words indicatingmay be used to identify forward-looking statements; however, the absence of these words does not mean that future outcomesthe statements are uncertain.not forward-looking. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statementsprojected, including, but not limited to:
conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;
changes in expected reserve or production levels;
changes in political or economic conditions in key operating markets,the jurisdictions in which we operate, including international markets;changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
capital available for exploration and development;
risks related to our hedging activities;
our level of success in integrating acquisitions;
well production timing;
drilling and operating risks;
availability of drilling rigs, materials and labor;
difficulty in obtaining necessary approvals and permits;
non-performance by third parties of contractual obligations;
unforeseen hazards such as weather conditions;
political conditions and developments, including political instability, 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 20142015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and those set forth from time to time in ourother 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 assumeWe undertake no dutyobligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 20142015 Annual Report on Form 10-K. AdditionalNotes 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, may be found in Notes 12 and 13 to the consolidated financial statements.measured.
Commodity Price Risk During the first six months of 2015,2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The table below providesfollowing tables provide a summary of open positions as of June 30, 2015:2016 and the weighted average price for those contracts:
| | Financial Instrument | Weighted Average Price | Barrels per day | Remaining Term | |
Crude Oil | | Crude Oil |
| | | Year Ending December 31, |
| | Third Quarter | Fourth Quarter | 2017 |
Three-Way Collars | | Three-Way Collars |
Volume (Bbls/day) | | 47,000 | — |
Price per Bbl: | | |
Ceiling | $70.34 | 35,000 | July- December 2015 (a) | $55.37 | — |
Floor | $55.57 | | $50.23 | — |
Sold put | $41.29 | | $40.96 | — |
| | |
Sold call options (a) | | |
Volume (Bbls/day) | | 10,000 | 35,000 |
Price per Bbl | | $72.39 | $61.91 |
Two-way Collars | | |
Volume (Bbls/day) | | 10,000 | — |
Price per Bbl: | | |
| — |
Ceiling | $71.84 | 12,000 | January- December 2016 | $50.00 | |
Floor | $60.48 | | $41.55 | |
Sold put | $50.00 | | |
| | |
Ceiling | $73.13 | 2,000 | January- June 2016 (b) | |
Floor | $65.00 | | |
Sold put | $50.00 | | |
Call Options | $72.39 | 10,000 | January- December 2016 (c) | |
| |
(a) | Counterparties haveCall options settle monthly. |
|
| | | |
Natural Gas |
| | Year Ending December 31, |
| Third Quarter | Fourth Quarter | 2017 |
Three-Way Collars (a) | | | |
Volume (MMBtu/day) | 20,000 | 20,000 | 40,000 |
Price per MMBtu | | | |
Ceiling | $2.93 | $2.93 | $3.28 |
Floor | $2.50 | $2.50 | $2.75 |
Sold put | $2.00 | $2.00 | $2.25 |
| |
(a) | On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $71.67$2.93 per barrelMMBtu indexed to NYMEX WTI,Henry Hub, which is exercisable on October 30, 2015.December 22, 2016. If counterparties exercise,counterparty exercises, the term of the fixed pricefixed-price swaps would be for the calendar year 20162017 and, if all such options are exercised, 25,000 barrels20,000 MMBtu per day. |
| |
| Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars. |
| |
(c)
| Call options settle monthly. |
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, 2015.2016.
| | (In millions) | Hypothetical Price Increase of 10% | Hypothetical Price Decrease of 10% | Hypothetical Price Increase of 10% | Hypothetical Price Decrease of 10% |
Crude oil commodity derivatives | $ | (67 | ) | $ | 51 |
| |
| | |
Crude oil derivatives | | $ | (32 | ) | $ | 73 |
|
Natural gas derivatives | | (5 | ) | 5 |
|
Total | | $ | (37 | ) | $ | 78 |
|
Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10 percent10% change in interest rates on financial assets and liabilities as of June 30, 2015,2016, is provided in the following table.
| | (In millions) | Fair Value | | Incremental Change in Fair Value | Fair Value | | Incremental Change in Fair Value |
Financial assets (liabilities):(a) | | | | | | |
Interest rate swap agreements | | $ | 12 |
| (b) | $ | 1 |
|
Long term debt, including amounts due within one year | $ | (8,720 | ) | (a)(b) | $ | (288 | ) | $ | (7,186 | ) | (b)(c) | $ | (287 | ) |
| |
(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. |
| |
(b)(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, 2015.2016.
During the second quarter of 2015,2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | | | | | | | | |
| Three Months Ended | | Six Months Ended |
| June 30, | | June 30, |
(In millions) | 2015 | | 2014 | | 2015 | | 2014 |
Segment Income (Loss) | | | | | | | |
North America E&P | $ | (45 | ) | | $ | 302 |
| | $ | (206 | ) | | $ | 544 |
|
International E&P | 41 |
| | 160 |
| | 64 |
| | 381 |
|
Oil Sands Mining | (77 | ) | | 55 |
| | (96 | ) | | 119 |
|
Segment income (loss) | (81 | ) | | 517 |
| | (238 | ) | | 1,044 |
|
Items not allocated to segments, net of income taxes | (305 | ) | | (157 | ) | | (424 | ) | | (286 | ) |
Income (loss) from continuing operations | (386 | ) | | 360 |
| | (662 | ) | | 758 |
|
Discontinued operations (a) | — |
| | 180 |
| | — |
| | 931 |
|
Net income (loss) | $ | (386 | ) | | $ | 540 |
| | $ | (662 | ) | | $ | 1,689 |
|
Capital Expenditures (b) | | | | | |
| | |
|
North America E&P | $ | 551 |
| | $ | 1,102 |
| | $ | 1,484 |
| | $ | 1,969 |
|
International E&P | 99 |
| | 115 |
| | 245 |
| | 220 |
|
Oil Sands Mining | 16 |
| | 55 |
| | 37 |
| | 123 |
|
Corporate | 12 |
| | 10 |
| | 14 |
| | 13 |
|
Discontinued operations (a) | — |
| | 141 |
| | — |
| | 251 |
|
Total | $ | 678 |
| | $ | 1,423 |
| | $ | 1,780 |
| | $ | 2,576 |
|
Exploration Expenses | | | | | |
| | |
|
North America E&P | $ | 91 |
| | $ | 82 |
| | $ | 126 |
| | $ | 139 |
|
International E&P | 20 |
| | 63 |
| | 75 |
| | 79 |
|
Total | $ | 111 |
| | $ | 145 |
| | $ | 201 |
| | $ | 218 |
|
| |
(a)
| As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014. |
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | | |
| Three Months Ended | | Six Months Ended |
| June 30, | | June 30, |
Net Sales Volumes | 2015 | | 2014 | | 2015 | | 2014 |
North America E&P | |
| | | | |
| | |
Crude Oil and Condensate (mbbld) | | | | | | | |
Bakken | 54 |
| | 44 | | 53 |
| | 41 |
Eagle Ford | 82 |
| | 67 | | 87 |
| | 65 |
Oklahoma Resource Basins | 5 |
| | 2 | | 5 |
| | 2 |
Other North America (c) | 35 |
| | 38 | | 35 |
| | 36 |
Total Crude Oil and Condensate | 176 |
| | 151 | | 180 |
| | 144 |
Natural Gas Liquids (mbbld) | | | | | | | |
Bakken | 3 |
| | 3 | | 3 |
| | 2 |
Eagle Ford | 26 |
| | 16 | | 26 |
| | 16 |
Oklahoma Resource Basins | 6 |
| | 6 | | 6 |
| | 5 |
Other North America (c) | 2 |
| | 2 | | 3 |
| | 4 |
Total Natural Gas Liquids | 37 |
| | 27 | | 38 |
| | 27 |
Total Liquid Hydrocarbons (mbbld) | | | | | | | |
Bakken | 57 |
| | 47 | | 56 |
| | 43 |
Eagle Ford | 108 |
| | 83 | | 113 |
| | 81 |
Oklahoma Resource Basins | 11 |
| | 8 | | 11 |
| | 7 |
Other North America (c) | 37 |
| | 40 | | 38 |
| | 40 |
Total Liquid Hydrocarbons | 213 |
| | 178 | | 218 |
| | 171 |
Natural Gas (mmcfd) | | | | | | | |
Bakken | 22 |
| | 18 | | 20 |
| | 17 |
Eagle Ford | 164 |
| | 111 | | 167 |
| | 109 |
Oklahoma Resource Basins | 81 |
| | 61 | | 79 |
| | 58 |
Other North America (c) | 94 |
| | 104 | | 94 |
| | 113 |
Total Natural Gas | 361 |
| | 294 | | 360 |
| | 297 |
Equivalent Barrels (mboed) | | | | | | | |
Bakken | 61 |
| | 50 | | 59 |
| | 46 |
Eagle Ford | 135 |
| | 102 | | 141 |
| | 99 |
Oklahoma Resource Basins | 24 |
| | 18 | | 24 |
| | 17 |
Other North America (c) | 54 |
| | 57 | | 54 |
| | 58 |
Total North America E&P | 274 |
| | 227 | | 278 |
| | 220 |
| |
(c)
| Includes Gulf of Mexico and other conventional onshore U.S. production. |
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | | | |
| Three Months Ended | | Six Months Ended |
| June 30, | | June 30, |
Net Sales Volumes | 2015 | | 2014 | | 2015 | | 2014 |
International E&P | | | | | | | |
Crude Oil and Condensate (mbbld) | | | | | | | |
Equatorial Guinea | 19 |
| | 20 |
| | 18 |
| | 22 |
United Kingdom | 14 |
| | 13 |
| | 14 |
| | 13 |
Total Crude Oil and Condensate | 33 |
| | 33 |
| | 32 |
| | 35 |
Natural Gas Liquids (mbbld) | | | | | | | |
Equatorial Guinea | 9 |
| | 11 |
| | 10 |
| | 11 |
Total Natural Gas Liquids | 9 |
| | 11 |
| | 10 |
| | 11 |
Total Liquid Hydrocarbons (mbbld) | | | | | | | |
Equatorial Guinea | 28 |
| | 31 |
| | 28 |
| | 33 |
United Kingdom | 14 |
| | 13 |
| | 14 |
| | 13 |
Total Liquid Hydrocarbons | 42 |
| | 44 |
| | 42 |
| | 46 |
Natural Gas (mmcfd) | | | | | | | |
Equatorial Guinea | 365 |
| | 446 |
| | 390 |
| | 441 |
United Kingdom (d) | 31 |
| | 28 |
| | 32 |
| | 29 |
Libya | — |
| | — |
| | — |
| | 1 |
Total Natural Gas | 396 |
| | 474 |
| | 422 |
| | 471 |
Equivalent Barrels (mboed) | | | | | | | |
Equatorial Guinea | 89 |
| | 105 |
| | 93 |
| | 107 |
United Kingdom (d) | 19 |
| | 18 |
| | 19 |
| | 18 |
Total International E&P | 108 |
| | 123 |
| | 112 |
| | 125 |
Oil Sands Mining | | | | | | | |
Synthetic Crude Oil (mbbld) (e) | 29 |
| | 44 |
| | 44 |
| | 45 |
Total Continuing Operations (mboed) | 411 |
| | 394 |
| | 434 |
| | 390 |
Discontinued Operations - Angola (mboed) (a) | — |
| | — |
| | — |
| | 3 |
Discontinued Operations - Norway (mboed) (a) | — |
| | 70 |
| | — |
| | 70 |
Total Company (mboed) | 411 |
| | 464 |
| | 434 |
| | 463 |
Net Sales Volumes of Equity Method Investees | | | | | | | |
LNG (mtd) | 4,991 |
| | 6,624 |
| | 5,629 |
| | 6,601 |
Methanol (mtd) | 673 |
| | 980 |
| | 778 |
| | 1,066 |
| |
(d)
| Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 5 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first six months of 2015 and 2014. |
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | |
| Three Months Ended | | Six Months Ended |
| June 30, | | June 30, |
Average Price Realizations (f) | 2015 | | 2014 | | 2015 | | 2014 |
North America E&P | | | | | | | |
Crude Oil and Condensate (per bbl) (g) | | | | | | | |
Bakken | $51.36 | | $93.08 | | $45.84 | | $91.43 |
Eagle Ford | 53.47 | | 99.08 | | 47.81 | | 97.65 |
Oklahoma Resource Basins | 51.00 | | 101.12 | | 48.34 | | 98.05 |
Other North America (c) | 52.83 | | 93.45 | | 47.10 | | 91.40 |
Total Crude Oil and Condensate | 52.63 | | 95.95 | | 47.11 | | 94.30 |
Natural Gas Liquids (per bbl) | | | | | | | |
Bakken | $11.63 | | $45.13 | | $7.19 | | $51.04 |
Eagle Ford | 14.08 | | 30.20 | | 13.90 | | 33.76 |
Oklahoma Resource Basins | 14.45 | | 33.04 | | 15.83 | | 38.21 |
Other North America (c) | 25.65 | | 54.13 | | 26.03 | | 57.65 |
Total Natural Gas Liquids | 14.77 | | 34.80 | | 14.60 | | 38.75 |
Total Liquid Hydrocarbons (per bbl) | | | | | | | |
Bakken | $49.29 | | $90.47 | | $43.72 | | $89.16 |
Eagle Ford | 44.05 | | 85.36 | | 40.01 | | 84.78 |
Oklahoma Resource Basins | 30.29 | | 52.00 | | 29.24 | | 55.04 |
Other North America (c) | 50.89 | | 90.45 | | 45.52 | | 88.97 |
Total Liquid Hydrocarbons | 45.96 | | 86.43 | | 41.37 | | 85.65 |
Natural Gas (per mcf) | | | | | | | |
Bakken | $2.62 | | $4.12 | | $2.76 | | $6.14 |
Eagle Ford | 2.71 | | 4.76 | | 2.79 | | 4.83 |
Oklahoma Resource Basins | 2.64 | | 4.57 | | 2.63 | | 5.01 |
Other North America (c) | 2.98 | | 5.65 | | 3.29 | | 5.35 |
Total Natural Gas | 2.76 | | 5.00 | | 2.88 | | 5.14 |
| |
(f)
| Excludes gains or losses on derivative instruments. |
| |
(g)
| Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realizations by $0.06 and $0.14 per bbl for the second quarter and first six months of 2015. There were no crude oil derivative instruments in 2014. |
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
|
| | | | | | | | | | |
| Three Months Ended | | Six Months Ended |
| June 30, | | June 30, |
Average Price Realizations | 2015 | | 2014 | | 2015 | | 2014 |
International E&P | | | | | | | |
Crude Oil and Condensate (per bbl) | | | | | | | |
Equatorial Guinea | $52.27 | | $90.91 | | $47.55 | | $90.66 |
United Kingdom | 62.97 | | 111.76 | | 60.19 | | 111.38 |
Total Crude Oil and Condensate | 56.70 | | 99.36 | | 52.92 | | 98.51 |
Natural Gas Liquids (per bbl) | | | | | | | |
Equatorial Guinea (h) | $1.00 | | $1.00 | | $1.00 | | $1.00 |
United Kingdom | 36.49 | | 64.37 | | 34.82 | | 69.56 |
Total Natural Gas Liquids | 3.10 | | 3.02 | | 3.29 | | 3.64 |
Total Liquid Hydrocarbons (per bbl) | | | | | | | |
Equatorial Guinea | $35.74 | | $59.72 | | $31.81 | | $61.12 |
United Kingdom | 61.93 | | 110.51 | | 58.96 | | 110.02 |
Total Liquid Hydrocarbons | 44.70 | | 75.41 | | 41.06 | | 75.48 |
Natural Gas (per mcf) | | | | | | | |
Equatorial Guinea (h) | $0.24 | | $0.24 | | $0.24 | | $0.24 |
United Kingdom | 6.98 | | 8.04 | | 7.34 | | 9.07 |
Libya | — |
| | — |
| | — |
| | 5.45 |
Total Natural Gas | 0.78 | | 0.69 | | 0.78 | | 0.80 |
Oil Sands Mining | | | | | | | |
Synthetic Crude Oil (per bbl) | $52.46 | | $94.17 | | $44.33 | | $91.27 |
Discontinued Operations - Angola (per boe) (a) | — |
| | — |
| | — |
| | $99.82 |
Discontinued Operations - Norway (per boe) (a) | — |
| | $108.11 | | — |
| | $108.09 |
| |
(h)
| Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment. |
Part II – OTHER INFORMATION
Item 1. Legal and Administrative Proceedings
We are a defendant in a number of lawsuitslegal 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.
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. Beginning in the second quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our development and/or operating costs. 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 20142015 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchasesrepurchases by Marathon Oil of its common stock during the quarter ended June 30, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.2016.
|
| | | | | | | | | | |
| Total Number of | | Average Price | | Total Number of Shares Purchased as Part of Publicly Announced | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the |
Period | Shares Purchased (a) | | Paid per Share | | Plans or Programs | | Plans or Programs |
04/01/15 - 04/30/15 | 151,874 |
| | 27.61 |
| | — |
| | $1,500,285,529 |
05/01/15 - 05/31/15 | 6,614 |
| | 29.85 |
| | — |
| | $1,500,285,529 |
06/01/15 - 06/30/15 | 3,231 |
| | 27.11 |
| | — |
| | $1,500,285,529 |
Total | 161,719 |
| | 27.69 |
| | — |
| | |
|
| | | | | | | | | | |
| Total Number of | | Average Price | | Total Number of Shares Purchased as Part of Publicly Announced | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the |
Period | Shares Purchased (a) | | Paid per Share | | Plans or Programs | | Plans or Programs |
04/01/16 - 04/30/16 | 103,922 |
| | $10.97 | | — |
| | n/a |
05/01/16 - 05/31/16 | 141,243 |
| | 13.56 |
| | — |
| | n/a |
06/01/16 - 06/30/16 | 486 |
| | 13.00 |
| | — |
| | n/a |
Total | 245,651 |
| | $12.46 | | — |
| | |
| |
(a) | 161,719245,651 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements. |
Item 6. Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this quarterly report on Form 10-Q.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | |
August 6, 20154, 2016 | | MARATHON OIL CORPORATION |
| | |
| By: | /s/ Gary E. Wilson |
| | Gary E. Wilson |
| | Vice President, Controller and Chief Accounting Officer |
| | (Duly Authorized Officer) |
Exhibit Index
|
| | | | | | | | |
| | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
Exhibit Number | | Exhibit Description | Form | | Exhibit | | Filing Date | |
2.1++ | | Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation | 8-K | | 2.1 | | 5/26/2011 | |
3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 10-Q | | 3.1 | | 8/8/2013 | |
3.2 | | Marathon Oil Corporation By-laws (Amended and restated as of April 9, 2015) | 8-K | | 3.1 | | 4/10/2015 | |
3.3 | | Specimen of Common Stock Certificate | 10-K | | 3.3 | | 2/28/2014 | |
4.1 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request | 10-K | | 4.1 | | 2/28/2014 | |
10.1 | | First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein | 10-Q | | 10.1 | | 5/07/2015 | |
12.1 | | Computation of Ratio of Earnings to Fixed Charges* | | | | | | |
31.1 | | Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934* | | | | | | |
31.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934* | | | | | | |
32.1 | | Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350* | | | | | | |
32.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350* | | | | | | |
101.INS | | XBRL Instance Document* | | | | | | |
101.SCH | | XBRL Taxonomy Extension Schema* | | | | | | |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase* | | | | | | |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase* | | | | | | |
101.LAB | | XBRL Taxonomy Extension Label Linkbase* | | | | | | |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase* | | | | | | |
* | | Filed herewith. | | | | | | |
++ | | Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request. |
|
| | | | | | | | |
| | | Incorporated by Reference (File No. 001-05153, unless otherwise indicated) |
Exhibit Number | | Exhibit Description | Form | | Exhibit | | Filing Date | |
3.1 | | Restated Certificate of Incorporation of Marathon Oil Corporation | 10-Q | | 3.1 | | 8/8/2013 | |
3.2 | | Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)* | | | | | | |
3.3 | | Specimen of Common Stock Certificate | 10-K | | 3.3 | | 2/28/2014 | |
4.1 | | Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request | 10-K | | 4.1 | | 2/28/2014 | |
10.1 | | Marathon Oil Corporation 2016 Incentive Compensation Plan | 14A | | App. A | | 4/07/2016 | |
12.1 | | Computation of Ratio of Earnings to Fixed Charges* | | | | | | |
31.1 | | Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934* | | | | | | |
31.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934* | | | | | | |
32.1 | | Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350* | | | | | | |
32.2 | | Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350* | | | | | | |
101.INS | | XBRL Instance Document* | | | | | | |
101.SCH | | XBRL Taxonomy Extension Schema* | | | | | | |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase* | | | | | | |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase* | | | | | | |
101.LAB | | XBRL Taxonomy Extension Label Linkbase* | | | | | | |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase* | | | | | | |
* | | Filed herewith. | | | | | | |