HOUSTON, Feb. 15, 2017 (GLOBE NEWSWIRE) -- Marathon Oil Corporation (NYSE:MRO) today reported a full-year 2016 net loss of $2,140 million, or $2.61 per diluted share. The net loss includes the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. The adjusted net loss for the year was $693 million or $0.85 per diluted share.
Full-Year 2016
- 2016 capital program at $1.1 billion, $300 million below original budget
- Total Company production averaged 393,000 net boed reflecting a return to production in Libya and contribution from OSM
- E&P production averaged 342,000 net boed, excluding Libya
- Strong operational results across all three resource plays, highlighted by year-over-year production growth in the Oklahoma resource basins of 40% and basin-leading Bakken wells
- Ended the year with 12 rigs operating in the U.S. resource plays
- Completed Alba B3 compression project in E.G., extending plateau production and field life
- Reduced production costs 33% for North America E&P and 15% for International E&P (excluding Libya) for full-year 2016 compared to the prior year
- Decreased total Company G&A expenses by 18% year over year
- Closed or announced non-core asset sales for approximately $1.3 billion, excluding closing adjustments
- Completed Oklahoma STACK acquisition of 61,000 net acres
- Reserve replacement of 112%, excluding dispositions, at approx. $13 per boe finding and development cost
- Year-end liquidity of $5.8 billion comprised of $2.5 billion in cash and an undrawn $3.3 billion revolving credit facility
"Despite challenging market conditions throughout 2016, we executed on our objectives of living within our means inclusive of non-core asset sales, while lowering costs and strengthening our balance sheet. We finished the year above the midpoint of E&P production guidance while spending significantly less than our original capital budget," said Marathon Oil President and CEO Lee Tillman. "We’re entering 2017 with a simplified portfolio more concentrated on our high-return, low-cost opportunities in the U.S. resource plays. Our $2.2 billion capital program accelerates sequential resource play production growth to the second quarter while providing exit rate momentum that positions us to deliver compound annual growth rates of 10-12 percent for total Company, excluding Libya, and 18-22 percent for our resource plays through 2021. Importantly, these production growth ranges apply to both oil as well as BOE, and we can achieve them within cash flows."
The Company reported a fourth quarter 2016 net loss of $1,371 million, or $1.62 per diluted share, and an adjusted net loss of $83 million or $0.10 per diluted share. Fourth quarter 2016 results included a charge of $1,346 million, which has no cash flow impact, to establish a valuation allowance against net deferred tax assets.
Fourth Quarter 2016
- Total Company production averaged 396,000 net boed, including Libya
- E&P production averaged 341,000 net boed, excluding Libya, in line with third quarter when adjusted for divestitures
- Oklahoma Resource Basins' production up 10% sequentially and more than 60% over year-ago quarter
- STACK activity focused on lease retention and delineation; reached total depth on first Company-operated Meramec spacing pilot
- Bakken maintained strong base production with no new wells to sales
- Eagle Ford oil production grew sequentially while achieving record low completed well costs
- North America E&P production costs reduced 2% sequentially and down more than 30% from the year-ago quarter
North America E&P
North America Exploration and Production (E&P) production available for sale averaged 212,000 net barrels of oil equivalent per day (boed) for fourth quarter 2016 compared to 216,000 net boed in third quarter 2016. On a divestiture-adjusted basis, production was flat with the prior quarter and down 8 percent from the year-ago period. Production from the three U.S. resource plays was also flat sequentially. Fourth quarter North America unit production costs were $5.66 per barrel of oil equivalent (boe), down 1 percent and 18 percent for the previous and year-ago quarters, respectively. Full-year unit production costs were $5.96 per boe, below the low end of guidance of $6.00 to $7.00 per boe.
OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 45,000 net boed during fourth quarter 2016, an increase of 10 percent compared to 41,000 net boed in the prior quarter and up about 60 percent compared to 28,000 net boed in the year-ago quarter. Marathon Oil brought online seven gross Company-operated STACK Meramec wells and one SCOOP Woodford well. Activity was predominately focused on lease retention and delineation in the STACK. The Company's first operated STACK infill spacing test, the Yost pilot, was drilled in fourth quarter and those five wells are expected to come to sales in first quarter 2017. The Company exited 2016 running five rigs, and plans to average approximately 10 rigs in 2017.
EAGLE FORD: Marathon Oil's production in the Eagle Ford averaged 94,000 net boed in fourth quarter 2016, compared to 97,000 net boed in the prior quarter and 128,000 net boed in the year-ago quarter. Eagle Ford oil production increased 2 percent compared to the prior quarter. The Company brought 52 gross Company-operated wells to sales with an average completed well cost of $3.9 million, down 20 percent from the year-ago quarter. These record low completed well costs were achieved despite increasing proppant loading per lateral foot up more than 70 percent compared to the year-ago quarter. Efficiency gains continued, with wells drilled at an average rate of 2,500 feet per day compared to 2,175 feet per day in the year-ago quarter. The Company ended the year with six drilling rigs, and expects to maintain that level of activity in 2017.
BAKKEN: In fourth quarter 2016, Marathon Oil's Bakken production averaged 52,000 net boed, down only slightly from the prior quarter's average of 54,000 net boed despite no new wells to sales, as strong well productivity and high reliability continued supporting the base production. The Maggie pad in East Myrmidon, brought online in the third quarter, continues to outperform expectations with basin-leading 90-day production rates. Since December, the Company has mobilized four rigs to Myrmidon to support the development program. It expects to average approximately six drilling rigs in the Bakken in 2017.
International E&P
International E&P production available for sale (excluding Libya) averaged 129,000 net boed for fourth quarter 2016, compared to 128,000 net boed in the prior quarter and up 5 percent compared to the year-ago quarter. Equatorial Guinea production available for sale averaged 109,000 net boed in fourth quarter 2016 compared to 110,000 net boed in the previous quarter and 104,000 net boed in the year-ago quarter. U.K. production available for sale averaged 19,000 net boed in fourth quarter 2016, up from 18,000 net boed in the previous quarter and 18,000 net boed in the year-ago quarter. In Libya, Marathon Oil had two liftings in fourth quarter 2016, with production available for sale averaging 8,000 net boed.
Fourth quarter International E&P production costs (excluding Libya) were $5.00 per boe. Full-year unit production costs of $4.41 per boe (excluding Libya) were below the low end of guidance of $4.50 to $5.50 per boe.
Oil Sands Mining
Oil Sands Mining (OSM) production available for sale for fourth quarter 2016 averaged 47,000 net barrels per day (bbld) compared to 58,000 net bbld in the prior quarter and 49,000 net bbld in the year-ago quarter. The decrease reflected planned maintenance activities in fourth quarter 2016. Operating expense per synthetic barrel (before royalties) was $26.52 in the fourth quarter.
Reserves
During 2016, Marathon Oil added proved reserves of 342 million barrels of oil equivalent (boe) through additions and acquisitions. This was virtually all in North America E&P, and largely from oil and condensate. Excluding dispositions, the reserve replacement ratio for the year was 112 percent with a finding and development (F&D) cost of just over $13 per boe. The Company's organic reserve replacement was 214 percent, excluding acquisitions, dispositions and revisions, at a drillbit F&D cost of less than $4.00. Net proved reserves were approximately 2.1 billion boe at year-end 2016.
Corporate and Special Items
Net cash provided by operating activities was $455 million during fourth quarter 2016, and net cash provided by operations before changes in working capital was $448 million. Cash additions to property, plant and equipment were $262 million in fourth quarter 2016. Total liquidity as of Dec. 31 was $5.8 billion, which consists of $2.5 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.3 billion.
During the quarter, the Company closed on the sale of certain non-operated CO2 and waterflood assets in West Texas and New Mexico for $235 million, excluding closing adjustments. The remaining portion of the Wyoming asset sale was also closed for proceeds of approximately $155 million, excluding closing adjustments. Since the beginning of 2016, Marathon Oil has announced or closed non-core asset sales of $1.3 billion.
Fourth quarter 2016 results included a $1.3 billion non-cash valuation allowance against U.S. net deferred tax assets as of Dec. 31, 2016, due to recent cumulative losses.
The Company's webcast commentary and associated slides related to Marathon Oil's financial and operational review, as well as the Quarterly Investor Packet, will be posted to the Company's website at http://ir.marathonoil.com and to its mobile app as soon as practicable following this release today, Feb. 15. The Company will conduct a question and answer webcast/call on Thursday, Feb. 16, at 10:00 a.m. ET. The associated commentary and answers to questions will include forward-looking information. To listen to the live webcast, visit the Marathon Oil website at http://www.marathonoil.com. The audio replay of the webcast will be posted by Feb. 17.
Non-GAAP Measures
In analyzing and planning for its business, Marathon Oil supplements its use of GAAP financial measures with non-GAAP financial measures, including adjusted net income (loss) and net cash provided by operations before changes in working capital, to evaluate the Company's financial performance between periods and to compare the Company's performance to certain competitors. Management also uses net cash provided by operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. The Company considers adjusted net income (loss) as another way to meaningfully represent our operational performance for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges, dispositions, pension settlements, and other items that could be considered “non-operating” or “non-core” in nature. These non-GAAP financial measures reflect an additional way of viewing aspects of the business that, when viewed with GAAP results may provide a more complete understanding of factors and trends affecting the business and are a useful tool to help management and investors make informed decisions about Marathon Oil's financial and operating performance. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. See the tables below for reconciliations between each non-GAAP financial measure and its most directly comparable GAAP financial measure. Marathon Oil strongly encourages investors to review the Company's consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
Forward-looking Statements
This release 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. All statements, other than statements of historical fact, including without limitation statements regarding the Company's future performance, business strategy, compound annual growth rate, asset quality, production guidance, drilling plans, capital plans and other plans and objectives for future operations, are forward-looking statements. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," "may," "plan," "project," "seek," "should," "target," "will," "would," or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause actual results to differ materially from those projected, including, but not limited to: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates; risks related to the Company's hedging activities; capital available for exploration and development; drilling and operating risks; well production timing; availability of drilling rigs, materials and labor; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the government 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 the Company’s 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.marathonoil.com. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
Media Relations Contact:
Lee Warren: 713-296-4103
Investor Relations Contact:
Zach Dailey: 713-296-4140
| Consolidated Statements of Income (Unaudited) | Three Months Ended | Year Ended | |||||||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | |||||||||||
| (In millions, except per share data) | 2016 | 2016 | 2015 | 2016 | 2015 | ||||||||||
| Revenues and other income: | |||||||||||||||
| Sales and other operating revenues, including related party | $ | 1,149 | $ | 1,020 | $ | 1,064 | $ | 3,753 | $ | 4,951 | |||||
| Marketing revenues | 51 | 80 | 100 | 278 | 571 | ||||||||||
| Income from equity method investments | 65 | 59 | 47 | 175 | 145 | ||||||||||
| Net gain (loss) on disposal of assets | 108 | 47 | 228 | 389 | 120 | ||||||||||
| Other income | 16 | 23 | 36 | 55 | 74 | ||||||||||
| Total revenues and other income | 1,389 | 1,229 | 1,475 | 4,650 | 5,861 | ||||||||||
| Costs and expenses: | |||||||||||||||
| Production | 340 | 295 | 394 | 1,313 | 1,694 | ||||||||||
| Marketing, including purchases from related parties | 56 | 80 | 98 | 282 | 569 | ||||||||||
| Other operating | 118 | 189 | 157 | 511 | 438 | ||||||||||
| Exploration | 34 | 83 | 532 | 330 | 1,318 | ||||||||||
| Depreciation, depletion and amortization | 631 | 594 | 668 | 2,395 | 2,957 | ||||||||||
| Impairments | 19 | 47 | 371 | 67 | 752 | ||||||||||
| Taxes other than income | 42 | 39 | 43 | 168 | 234 | ||||||||||
| General and administrative | 96 | 105 | 126 | 484 | 590 | ||||||||||
| Total costs and expenses | 1,336 | 1,432 | 2,389 | 5,550 | 8,552 | ||||||||||
| Income (loss) from operations | 53 | (203 | ) | (914 | ) | (900 | ) | (2,691 | ) | ||||||
| Net interest and other | (77 | ) | (87 | ) | (87 | ) | (335 | ) | (267 | ) | |||||
| Income (loss) before income taxes | (24 | ) | (290 | ) | (1,001 | ) | (1,235 | ) | (2,958 | ) | |||||
| Provision (Benefit) for income taxes | 1,347 | (98 | ) | (208 | ) | 905 | (754 | ) | |||||||
| Net income (loss) | $ | (1,371 | ) | $ | (192 | ) | $ | (793 | ) | $ | (2,140 | ) | $ | (2,204 | ) |
| Adjustments for special items (pre-tax): | |||||||||||||||
| Net (gain) loss on dispositions | (108 | ) | (38 | ) | (229 | ) | (379 | ) | (122 | ) | |||||
| Proved property impairments | — | 47 | 28 | 47 | 405 | ||||||||||
| Unproved property impairments | — | — | 302 | 118 | 855 | ||||||||||
| Goodwill Impairment | — | — | 340 | — | 340 | ||||||||||
| Loss on Equity Method Investment | — | — | — | — | 12 | ||||||||||
| Pension settlement | 10 | 14 | 20 | 103 | 119 | ||||||||||
| Unrealized (gain) loss on derivative instruments | 21 | (25 | ) | 9 | 110 | (50 | ) | ||||||||
| Reduction in workforce | — | — | 8 | 8 | 55 | ||||||||||
| Rig termination payment | — | 113 | — | 113 | — | ||||||||||
| Other | (4 | ) | 37 | 20 | 47 | 20 | |||||||||
| Provision (benefit) for income taxes related to special items | 23 | (53 | ) | (28 | ) | (66 | ) | (434 | ) | ||||||
| Alberta provincial corporate tax rate increase | — | — | — | — | 135 | ||||||||||
| Valuation Allowance | 1,346 | — | — | 1,346 | — | ||||||||||
| Adjusted net income (loss) (a) | $ | (83 | ) | $ | (97 | ) | $ | (323 | ) | $ | (693 | ) | $ | (869 | ) |
| Per diluted share: | |||||||||||||||
| Net Income (loss) | $ | (1.62 | ) | $ | (0.23 | ) | $ | (1.17 | ) | $ | (2.61 | ) | $ | (3.26 | ) |
| Adjusted net income (loss) (a) | $ | (0.10 | ) | $ | (0.11 | ) | $ | (0.48 | ) | $ | (0.85 | ) | $ | (1.28 | ) |
| Weighted average diluted shares | 847 | 847 | 678 | 819 | 677 | ||||||||||
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.
| Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | |||||||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | |||||||||||
| (in millions) | 2016 | 2016 | 2015 | 2016 | 2015 | ||||||||||
| Segment income (loss) | |||||||||||||||
| North America E&P | $ | (91 | ) | $ | (59 | ) | $ | (219 | ) | $ | (415 | ) | $ | (486 | ) |
| International E&P | 110 | 59 | 19 | 228 | 112 | ||||||||||
| Oil Sands Mining | 16 | 15 | (6 | ) | (55 | ) | (113 | ) | |||||||
| Segment income (loss) | 35 | 15 | (206 | ) | (242 | ) | (487 | ) | |||||||
| Not allocated to segments | (1,406 | ) | (207 | ) | (587 | ) | (1,898 | ) | (1,717 | ) | |||||
| Net income (loss) | $ | (1,371 | ) | $ | (192 | ) | $ | (793 | ) | $ | (2,140 | ) | $ | (2,204 | ) |
| Exploration expenses | |||||||||||||||
| North America E&P | $ | 37 | $ | 35 | $ | 214 | $ | 127 | $ | 362 | |||||
| International E&P | (3 | ) | 10 | 16 | 17 | 101 | |||||||||
| Oil Sands Mining | — | — | — | 7 | — | ||||||||||
| Segment exploration expenses | 34 | 45 | 230 | 151 | 463 | ||||||||||
| Not allocated to segments | — | 38 | 302 | 179 | 855 | ||||||||||
| Total | $ | 34 | $ | 83 | $ | 532 | $ | 330 | $ | 1,318 | |||||
| Cash flows | |||||||||||||||
| Net cash provided by operating activities | $ | 455 | $ | 366 | $ | 352 | $ | 1,073 | $ | 1,565 | |||||
| Minus: changes in working capital | 7 | 78 | 74 | (8 | ) | (112 | ) | ||||||||
| Net cash provided by operations before changes in working capital (a) | $ | 448 | $ | 288 | $ | 278 | $ | 1,081 | $ | 1,677 | |||||
| Cash additions to property, plant and equipment | $ | (262 | ) | $ | (230 | ) | $ | (528 | ) | $ | (1,245 | ) | $ | (3,476 | ) |
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.
| Three Months Ended | Year Ended | |||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
| (mboed) | 2016 | 2016 | 2015 | 2016 | 2015 | |||||
| Net production available for sale | ||||||||||
| North America E&P (a) | 212 | 216 | 260 | 223 | 270 | |||||
| International E&P excluding Libya (b) | 129 | 128 | 123 | 119 | 116 | |||||
| Combined North America & International E&P, excluding Libya (b) | 341 | 344 | 383 | 342 | 386 | |||||
| Oil Sands Mining (c) | 47 | 58 | 49 | 48 | 45 | |||||
| Total Company excluding Libya | 388 | 402 | 432 | 390 | 431 | |||||
| Libya | 8 | — | — | 3 | — | |||||
| Total Company | 396 | 402 | 432 | 393 | 431 | |||||
(a) The Company closed on asset sales of certain fields within New Mexico and West Texas in July, August, and October 2016. Certain Wyoming assets closed in June and November 2016. East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets closed in August 2015; and the sale of certain Gulf of Mexico assets closed in December 2015 and February 2016.
(b) Libya is excluded because of timing of future production and sales levels.
(c) Upgraded bitumen excluding blendstocks.
| Three Months Ended | Year Ended | |||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
| (mboed) | 2016 | 2016 | 2015 | 2016 | 2015 | |||||
| Net production available for sale | ||||||||||
| North America E&P | 212 | 216 | 260 | 223 | 270 | |||||
| Less: Divestitures (a) | (3 | ) | (7 | ) | (32 | ) | (13 | ) | (36 | ) |
| Divestiture-adjusted North America E&P | 209 | 209 | 228 | 210 | 234 | |||||
| Divestiture-adjusted Total Company | 393 | 395 | 400 | 380 | 395 | |||||
(a) Divestitures include the sale of certain New Mexico and West Texas assets in July, August, and October 2016; Wyoming assets closed in June and November 2016; East Texas, North Louisiana and Wilburton, Oklahoma assets closed in August 2015; and the sale of certain Gulf of Mexico assets closed in December 2015 and February 2016. These production volumes have been removed from all periods shown in arriving at divestiture-adjusted North America E&P net production available for sale.
| Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | ||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | ||||||
| 2016 | 2016 | 2015 | 2016 | 2015 | ||||||
| North America E&P - net sales volumes | ||||||||||
| Liquid hydrocarbons (mbbld) | 160 | 164 | 200 | 171 | 210 | |||||
| Bakken | 47 | 50 | 52 | 50 | 55 | |||||
| Eagle Ford | 74 | 76 | 99 | 82 | 106 | |||||
| Oklahoma resource basins | 24 | 22 | 13 | 18 | 12 | |||||
| Other North America (a) | 15 | 16 | 36 | 21 | 37 | |||||
| Crude oil and condensate (mbbld) | 121 | 122 | 159 | 131 | 171 | |||||
| Bakken | 41 | 44 | 48 | 44 | 51 | |||||
| Eagle Ford | 54 | 54 | 72 | 60 | 80 | |||||
| Oklahoma resource basins | 13 | 11 | 5 | 9 | 5 | |||||
| Other North America (a) | 13 | 13 | 34 | 18 | 35 | |||||
| Natural gas liquids (mbbld) | 39 | 42 | 41 | 40 | 39 | |||||
| Bakken | 6 | 6 | 4 | 6 | 4 | |||||
| Eagle Ford | 20 | 22 | 27 | 22 | 26 | |||||
| Oklahoma resource basins | 11 | 11 | 8 | 9 | 7 | |||||
| Other North America (a) | 2 | 3 | 2 | 3 | 2 | |||||
| Natural gas (mmcfd) | 315 | 315 | 345 | 314 | 351 | |||||
| Bakken | 26 | 25 | 27 | 25 | 22 | |||||
| Eagle Ford | 119 | 127 | 166 | 137 | 165 | |||||
| Oklahoma resource basins | 123 | 116 | 89 | 102 | 81 | |||||
| Other North America (a) | 47 | 47 | 63 | 50 | 83 | |||||
| Total North America E&P (mboed) | 212 | 216 | 258 | 223 | 269 | |||||
| International E&P - net sales volumes | ||||||||||
| Liquid hydrocarbons (mbbld) | 64 | 44 | 43 | 46 | 43 | |||||
| Equatorial Guinea | 32 | 38 | 29 | 31 | 29 | |||||
| United Kingdom | 22 | 6 | 14 | 12 | 14 | |||||
| Libya | 10 | — | — | 3 | — | |||||
| Crude oil and condensate (mbbld) | 52 | 32 | 32 | 35 | 33 | |||||
| Equatorial Guinea | 20 | 26 | 18 | 20 | 19 | |||||
| United Kingdom | 22 | 6 | 14 | 12 | 14 | |||||
| Libya | 10 | — | — | 3 | — | |||||
| Natural gas liquids (mbbld) | 12 | 12 | 11 | 11 | 10 | |||||
| Equatorial Guinea | 12 | 12 | 11 | 11 | 10 | |||||
| United Kingdom | — | — | — | — | — | |||||
| Natural gas (mmcfd) | 482 | 489 | 467 | 453 | 439 | |||||
| Equatorial Guinea | 454 | 462 | 438 | 425 | 410 | |||||
| United Kingdom (b) | 28 | 27 | 29 | 28 | 29 | |||||
| Total International E&P (mboed) | 145 | 126 | 121 | 122 | 116 | |||||
| Oil Sands Mining - net sales volumes | ||||||||||
| Synthetic crude oil (mbbld) (c) | 62 | 65 | 59 | 59 | 53 | |||||
| Total Company - net sales volumes (mboed) | 419 | 407 | 438 | 404 | 438 | |||||
| Net sales volumes of equity method investees | ||||||||||
| LNG (mtd) | 6,743 | 6,620 | 6,569 | 5,874 | 5,884 | |||||
| Methanol (mtd) | 1,316 | 1,529 | 1,064 | 1,358 | 937 | |||||
| Condensate and LPG (boed) | 15,381 | 16,766 | 13,580 | 13,430 | 12,208 | |||||
(a) Includes Gulf of Mexico, Wyoming and other conventional onshore U.S. production. The sale of certain Gulf of Mexico assets closed in December 2015 and February 2016, and Wyoming in June 2016.
(b) Includes natural gas acquired for injection and subsequent resale of 5 mmcfd, 5 mmcfd, 8 mmcfd, 5 mmcfd, and 8 mmcfd in the fourth and third quarter and of 2016, and fourth quarter of 2015, and the years 2016and 2015, respectively.
(c) Includes blendstocks.
| Supplemental Statistics (Unaudited) | Three Months Ended | Year Ended | |||||||||||||
| Dec. 31 | Sept. 30 | Dec. 31 | Dec. 31 | Dec. 31 | |||||||||||
| 2016 | 2016 | 2015 | 2016 | 2015 | |||||||||||
| North America E&P - average price realizations (a) | |||||||||||||||
| Liquid hydrocarbons ($ per bbl) | $ | 39.00 | $ | 34.00 | $ | 32.47 | $ | 32.71 | $ | 37.85 | |||||
| Bakken | 41.96 | 37.33 | 36.03 | 35.65 | 40.23 | ||||||||||
| Eagle Ford | 38.16 | 32.81 | 31.34 | 31.61 | 36.75 | ||||||||||
| Oklahoma resource basins | 34.28 | 27.60 | 22.66 | 28.15 | 25.84 | ||||||||||
| Other North America (b) | 41.69 | 37.91 | 33.98 | 33.96 | 41.16 | ||||||||||
| Crude oil and condensate ($ per bbl) (c) | $ | 45.89 | $ | 41.35 | $ | 37.71 | $ | 38.57 | $ | 43.50 | |||||
| Bakken | 46.28 | 41.25 | 38.81 | 39.25 | 42.72 | ||||||||||
| Eagle Ford | 45.96 | 41.67 | 38.27 | 38.76 | 44.45 | ||||||||||
| Oklahoma resource basins | 46.30 | 42.04 | 38.29 | 41.78 | 43.78 | ||||||||||
| Other North America (b) | 43.78 | 39.89 | 34.79 | 34.93 | 42.42 | ||||||||||
| Natural gas liquids ($ per bbl) | $ | 17.31 | $ | 12.44 | $ | 12.53 | $ | 13.15 | $ | 13.37 | |||||
| Bakken | 11.97 | 10.63 | 5.75 | 8.56 | 6.12 | ||||||||||
| Eagle Ford | 16.34 | 11.45 | 12.65 | 12.40 | 13.14 | ||||||||||
| Oklahoma resource basins | 20.79 | 13.87 | 12.80 | 15.84 | 13.90 | ||||||||||
| Other North America (b) | 24.56 | 22.50 | 22.78 | 23.51 | 24.63 | ||||||||||
| Natural gas ($ per mcf) (d) | $ | 2.87 | $ | 2.67 | $ | 2.12 | $ | 2.38 | $ | 2.66 | |||||
| Bakken | 2.63 | 1.95 | 1.62 | 2.12 | 2.23 | ||||||||||
| Eagle Ford | 2.91 | 2.72 | 2.15 | 2.37 | 2.64 | ||||||||||
| Oklahoma resource basins | 2.90 | 2.74 | 2.14 | 2.47 | 2.54 | ||||||||||
| Other North America (b) | 2.82 | 2.73 | 2.22 | 2.38 | 2.93 | ||||||||||
| International E&P - average price realizations | |||||||||||||||
| Liquid hydrocarbons ($ per bbl) | $ | 37.85 | $ | 30.40 | $ | 29.18 | $ | 32.10 | $ | 36.67 | |||||
| Equatorial Guinea | 26.60 | 27.44 | 22.82 | 25.78 | 28.50 | ||||||||||
| United Kingdom | 45.02 | 48.01 | 41.85 | 42.52 | 53.00 | ||||||||||
| Libya | 57.69 | — | — | 57.69 | — | ||||||||||
| Crude oil and condensate ($ per bbl) | $ | 46.14 | $ | 41.45 | $ | 38.43 | $ | 41.70 | $ | 47.50 | |||||
| Equatorial Guinea | 41.60 | 39.70 | 35.42 | 38.85 | 42.83 | ||||||||||
| United Kingdom | 45.18 | 49.82 | 42.17 | 43.21 | 53.91 | ||||||||||
| Libya | 57.69 | — | — | 57.69 | — | ||||||||||
| Natural gas liquids ($ per bbl) | $ | 1.72 | $ | 1.93 | $ | 2.08 | $ | 2.11 | $ | 2.81 | |||||
| Equatorial Guinea (e) | 1.00 | 1.00 | 1.00 | 1.00 | 1.00 | ||||||||||
| United Kingdom | 32.58 | 26.36 | 31.01 | 26.41 | 32.53 | ||||||||||
| Natural gas ($ per mcf) | $ | 0.53 | $ | 0.46 | $ | 0.58 | $ | 0.52 | $ | 0.68 | |||||
| Equatorial Guinea (e) | 0.24 | 0.24 | 0.24 | 0.24 | 0.24 | ||||||||||
| United Kingdom | 5.39 | 4.19 | 5.73 | 4.80 | 6.85 | ||||||||||
| Oil Sands Mining - average price realizations | |||||||||||||||
| Synthetic crude oil ($ per bbl) | $ | 43.35 | $ | 39.59 | $ | 34.65 | $ | 37.57 | $ | 40.13 | |||||
| Benchmark | |||||||||||||||
| WTI crude oil (per bbl) | $ | 49.29 | $ | 44.94 | $ | 42.16 | $ | 43.47 | $ | 48.76 | |||||
| Brent (Europe) crude oil (per bbl)(f) | $ | 49.19 | $ | 45.79 | $ | 43.56 | $ | 43.55 | $ | 52.35 | |||||
| Henry Hub natural gas (per mmbtu)(g) | $ | 2.98 | $ | 2.81 | $ | 2.27 | $ | 2.46 | $ | 2.66 | |||||
| WCS crude oil (per bbl)(h) | $ | 34.97 | $ | 31.44 | $ | 27.69 | $ | 29.48 | $ | 35.28 | |||||
(a) Excludes gains or losses on derivative instruments.
(b) Includes Gulf of Mexico and other conventional onshore U.S. production. The sale of certain Gulf of Mexico assets closed in December 2015 and February 2016.
(c) Inclusion of realized gains on crude oil derivative instruments would have increased average price realizations by $0.32, $1.55, $3.03, $0.92, and $1.24 for the fourth and third quarter and of 2016, and fourth quarter of 2015, and the years 2016 and 2015, respectively.
(d) Inclusion of realized gains (losses) on natural gas derivative instruments would have a de minimus impact on average price realizations for the periods presented.
(e) Represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and/or Equatorial Guinea LNG Holdings Limited, which are equity method investees. The Alba Plant LLC processes the NGLs and then sells secondary condensate, propane, and butane at market prices. Marathon Oil includes its share of income from each of these equity method investees in the International E&P segment.
(f) Average of monthly prices obtained from Energy Information Administration ("EIA") website.
(g) Settlement date average per mmbtu.
(h) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
| Estimated Net Proved Reserves | |||||||||
| North America E&P | International E&P | OSM | Total | ||||||
| Total (mmboe) | Total (mmboe) | SCO (mmbbl) | (mmboe) | ||||||
| As of Dec. 31, 2015 | 944 | 521 | 698 | 2,163 | |||||
| Additions | 307 | 1 | — | 308 | |||||
| Revisions | (171 | ) | (22 | ) | 12 | (181 | ) | ||
| Acquisitions | 34 | — | — | 34 | |||||
| Dispositions | (84 | ) | — | — | (84 | ) | |||
| Production | (82 | ) | (44 | ) | (18 | ) | (144 | ) | |
| As of Dec. 31, 2016 | 948 | 456 | 692 | 2,096 | |||||
| Changes in Reserves (excluding dispositions) (mmboe) | 161 | ||||||||
| Production (mmboe) | 144 | ||||||||
| Reserve Replacement Ratio (excluding dispositions) (a) | 112 | % | |||||||
| Organic Changes in Reserves (excluding acquisitions, dispositions, revisions) (mmboe) | 308 | ||||||||
| Production (mmboe) | 144 | ||||||||
| Organic Reserve Replacement Ratio (excluding acquisitions, dispositions & revisions) (a) | 214 | % | |||||||
| Finding Costs ($ in millions, except as indicated) | 2016 | ||||||||
| Cost Incurred | $ | 2,113 | |||||||
| Changes in Reserves (excluding dispositions) (mmboe) | 161 | ||||||||
| Finding and development costs per BOE | $ | 13.12 | |||||||
| Costs Incurred | $ | 2,113 | |||||||
| Property Acquisition Costs | (908 | ) | |||||||
| Capitalized Asset Retirement Costs | (109 | ) | |||||||
| Adjusted Finding and Development costs (a) | $ | 1,096 | |||||||
| Organic Changes in Reserves (excluding acquisitions, dispositions, revisions) (mmboe) | 308 | ||||||||
| Adjusted finding and development costs per BOE (a) | $ | 3.56 | |||||||
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.