Marathon Oil Reports Third Quarter 2016 Results
Highlights
- Third quarter total Company production averaged 402,000 net boed, above the top end of guidance and up 5% sequentially
- Oklahoma Resource Basins' production up more than 50% sequentially and nearly 80% over year-ago quarter
- Strong well results across all three resource plays, highlighted by: STACK volatile oil well 30-day rate of 2,845 boed (69% oil); Bakken Three Forks well 30-day rate of 2,635 boed (80% oil); Lower Eagle Ford well 30-day rate of 2,285 boed (81% oil)
- 8% sequential production increase in Equatorial Guinea driven by Alba B3 compression project brought online in early July
- Production costs reduced sequentially more than 10% for North America E&P and nearly 20% for International E&P (excluding Libya)
- Closed sale of non-operated CO2 and waterflood assets in West Texas and New Mexico for \\$235 million; more than \\$1.5 billion in non-core asset sales announced or closed since August 2015
- 2016 capital program remains at \\$1.3 billion including planned 50% increase in rig activity by year end
"Strong execution across our entire business led to third quarter production above the top end of our guidance and cash flow neutrality," said Marathon Oil President and CEO Lee Tillman. "We're increasing our rig count by 50 percent in the fourth quarter while remaining within our existing \\$1.3 billion capital program. This acceleration will have us well positioned to resume sequential production growth in the resource plays by the second half of 2017. Our planning process continues, but the preliminary five-year view for the resource plays supports compounded annual growth rate of 15 to 20 percent within cash flows at flat \\$55 WTI."
North America E&P
North America Exploration and Production (E&P) production available for sale averaged 216,000 net barrels of oil equivalent per day (boed) for third quarter 2016 compared to 224,000 net boed in second quarter 2016. On a divestiture-adjusted basis, production was up 3 percent over the prior quarter and down 7 percent from the year-ago period. Third quarter North America production costs were 12 percent lower than the previous quarter and 37 percent lower than the year-ago period. Unit production costs were \\$5.70 per barrel of oil equivalent (boe), down 9 percent and 23 percent for the previous and year-ago quarters, respectively.
OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 41,000 net boed during third quarter 2016, an increase of 52 percent compared to 27,000 net boed in the prior quarter and up 78 percent compared to 23,000 net boed in the year-ago quarter. During third quarter 2016, Marathon Oil brought online 10 gross Company-operated STACK Meramec wells and two SCOOP Woodford wells. The Marjorie and Lloyd volatile oil wells, both extended lateral (XL) Meramec wells in eastern Blaine County, achieved 30-day production rates of 2,845 boed (69 percent oil) and 2,010 boed (73 percent oil), respectively. Both wells were completed with 2,900 pounds of proppant per lateral foot. The Firestone well, a standard lateral black oil well in Kingfisher County, achieved a 30-day production rate of 1,810 boed (47 percent oil). In Canadian County, the Hrdy single lateral well had a 30-day rate of 1,870 boed (56 percent oil). The Company is further increasing activity from four to five rigs in the fourth quarter, with activity focused in the STACK.
EAGLE FORD: In third quarter 2016, Marathon Oil's production in the Eagle Ford averaged 97,000 net boed, compared to 109,000 net boed in the prior quarter and 128,000 net boed in the year-ago quarter. The sequential production decrease was in line with expectations due to base declines and activity levels. During third quarter 2016, the Company brought 36 gross (24 net) operated wells to sales, of which 20 were lower Eagle Ford, 15 upper Eagle Ford and one Austin Chalk. The unbounded Hausmann Lower Eagle Ford oil well, completed with a more intense stimulation and 200-foot stage spacing, averaged 2,285 boed (81 percent oil) over 30 days. The Bailey Retzloff 508 Upper Eagle Ford condensate well achieved a 30-day rate of 2,345 boed (50 percent oil). Third quarter completed well costs were below \\$4 million, down approximately 20 percent from the year-ago quarter. The Company expects to increase activity from four to six rigs in the fourth quarter.
BAKKEN: Marathon Oil averaged 54,000 net boed of production in the Bakken during third quarter 2016, compared to 53,000 net boed in the prior quarter and 61,000 net boed in the year-ago quarter as strong well productivity from the Clarks Creek pad and high reliability continued supporting the base production. Three gross wells in East Myrmidon were brought to sales in the third quarter, all performing at or above expectations with completions ranging from 600 to 1,500 pounds per lateral foot of proppant and 45 to 50 stages per well. The Rufus well in the first bench of the Three Forks achieved a 30-day production rate of 2,635 boed (80 percent oil), and the Hannah Three Forks first bench well achieved 2,100 boed (80 percent oil). Additionally, the Maggie Middle Bakken well achieved 2,190 boed (80 percent oil) over 30 days. Completed well costs averaged below \\$6 million per well. The Company plans to return to drilling in the Bakken with one rig to be added in the fourth quarter.
International E&P
International E&P production available for sale (excluding Libya) averaged 128,000 net boed for third quarter 2016, an increase of 7 percent compared to the prior quarter and up 12 percent compared to the year-ago quarter. Third quarter 2016 production benefited from the Alba B3 compression project in Equatorial Guinea, which came online in early July. Equatorial Guinea production available for sale averaged 110,000 net boed in third quarter 2016 compared to 102,000 net boed in the previous quarter and 99,000 net boed in the year-ago quarter. U.K. production available for sale averaged 18,000 net boed in third quarter 2016, flat compared to the previous quarter and up compared to 15,000 net boed in the year-ago quarter.
Third quarter International E&P production costs (excluding Libya) were 19 percent lower than the previous quarter and 43 percent below the year-ago quarter. Unit production costs (excluding Libya) were \\$3.31 per boe, down 24 percent and 46 percent for the previous and year-ago quarters, respectively.
Oil Sands Mining
Oil Sands Mining (OSM) production available for sale for third quarter 2016 averaged 58,000 net barrels per day (bbld) compared to 40,000 net bbld in the prior quarter and 57,000 net bbld in the year-ago quarter. Record production in third quarter 2016 was due to strong reliability at the mines and upgrader and less downtime compared to second quarter 2016 when wildfires caused disruptions. Operating expense per synthetic barrel (before royalties) was \\$20.69, 20 percent lower than the year-ago quarter due primarily to cost reduction efforts. It was the lowest per unit cost performance by OSM to date.
Guidance
Marathon Oil expects fourth quarter 2016 North America E&P production available for sale to average 205,000 to 215,000 net boed. Fourth quarter International E&P production available for sale (excluding Libya) is expected to be within a range of 120,000 to 130,000 net boed. While force majeure was lifted in September at the Es Sider terminal in Libya, Marathon Oil continues to exclude Libya volumes from its production forecasts. OSM synthetic crude oil production is expected to range from 40,000 to 45,000 net bbld.
The Company is raising the low end of its full-year 2016 E&P production guidance range, resulting in a new range of 335,000 to 345,000 net boed. Full-year production guidance for OSM was narrowed to 45,000 to 50,000 net bbld.
Corporate and Special Items
Net cash provided by operating activities was \\$366 million during third quarter 2016, and net cash provided by operations before changes in working capital was \\$288 million. Cash additions to property, plant and equipment were \\$230 million in third quarter 2016. Total liquidity as of September 30 was \\$5.3 billion, which consists of \\$2 billion in cash and cash equivalents and an undrawn revolving credit facility of \\$3.3 billion.
In late October, the Company closed on the sale of certain non-operated CO2 and waterflood assets in West Texas and New Mexico for \\$235 million. Since August 2015, Marathon Oil has announced or closed non-core asset sales in excess of \\$1.5 billion. The Company is on track to close the remaining portion of the Wyoming asset sale by year-end.
The adjustments to net loss for third quarter 2016 total \\$148 million before tax and largely consist of: a Gulf of Mexico rig termination payment of \\$113 million and impairments to proved property of \\$47 million, partially offset by a net gain on the sale of assets of \\$38 million and an unrealized gain on commodity derivatives of \\$25 million.
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, Nov. 2. The Company will conduct a question and answer webcast/call on Thursday, Nov. 3, at 9:00 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 Nov. 4.
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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, reserve estimates, compound annual growth rate, asset quality, production guidance, drilling plans, capital plans, cost and expense estimates, asset acquisitions and sales, future financial position, 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 economic conditions in the jurisdictions in which the Company operates, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions; risks related to the Company's hedging activities; the Company's level of success in integrating acquisitions; capital available for exploration and development; drilling and operating risks; well production timing; availability of 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 terrorism, 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 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. The Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
| Consolidated Statements of Income (Unaudited) | Three Months Ended | ||||||||
| Sept. 30 | June 30 | Sept. 30 | |||||||
| (In millions, except per share data) | 2016 | 2016 | 2015 | ||||||
| Revenues and other income: | |||||||||
| Sales and other operating revenues, including related party | \\$ | 1,020 | \\$ | 870 | \\$ | 1,300 | |||
| Marketing revenues | 80 | 89 | 84 | ||||||
| Income from equity method investments | 59 | 37 | 36 | ||||||
| Net gain (loss) on disposal of assets | 47 | 294 | (109 | ) | |||||
| Other income | 23 | 12 | 12 | ||||||
| Total revenues and other income | 1,229 | 1,302 | 1,323 | ||||||
| Costs and expenses: | |||||||||
| Production | 295 | 350 | 406 | ||||||
| Marketing, including purchases from related parties | 80 | 88 | 84 | ||||||
| Other operating | 189 | 95 | 93 | ||||||
| Exploration | 83 | 189 | 585 | ||||||
| Depreciation, depletion and amortization | 594 | 561 | 717 | ||||||
| Impairments | 47 | — | 337 | ||||||
| Taxes other than income | 39 | 39 | 46 | ||||||
| General and administrative | 105 | 132 | 125 | ||||||
| Total costs and expenses | 1,432 | 1,454 | 2,393 | ||||||
| Income (loss) from operations | (203 | ) | (152 | ) | (1,070 | ) | |||
| Net interest and other | (87 | ) | (86 | ) | (75 | ) | |||
| Income (loss) before income taxes | (290 | ) | (238 | ) | (1,145 | ) | |||
| Benefit for income taxes | (98 | ) | (68 | ) | (396 | ) | |||
| Net income (loss) | \\$ | (192 | ) | \\$ | (170 | ) | \\$ | (749 | ) |
| Adjustments for special items (pre-tax): | |||||||||
| Net (gain) loss on dispositions | (38 | ) | (296 | ) | 109 | ||||
| Proved property impairments | 47 | — | 333 | ||||||
| Unproved property impairments | — | 118 | 553 | ||||||
| Loss on Equity Method Investment | — | — | 12 | ||||||
| Pension settlement | 14 | 31 | 18 | ||||||
| Unrealized (gain) loss on commodity derivative instruments | (25 | ) | 91 | (80 | ) | ||||
| Reduction in workforce | — | 1 | 4 | ||||||
| Rig termination payment | 113 | — | — | ||||||
| Other | 37 | 14 | — | ||||||
| Provision (benefit) for income taxes related to special items | (53 | ) | 15 | (338 | ) | ||||
| Adjusted net income (loss) (a) | \\$ | (97 | ) | \\$ | (196 | ) | \\$ | (138 | ) |
| Per diluted share: | |||||||||
| Net Income (loss) | \\$ | (0.23 | ) | \\$ | (0.20 | ) | \\$ | (1.11 | ) |
| Adjusted net income (loss) (a) | \\$ | (0.11 | ) | \\$ | (0.23 | ) | \\$ | (0.20 | ) |
| Weighted average diluted shares | 847 | 848 | 677 | ||||||
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.
| Supplemental Statistics (Unaudited) | Three Months Ended | ||||||||
| Sept. 30 | June 30 | Sept. 30 | |||||||
| (in millions) | 2016 | 2016 | 2015 | ||||||
| Segment income (loss) | |||||||||
| North America E&P | \\$ | (59 | ) | \\$ | (70 | ) | \\$ | (61 | ) |
| International E&P | 59 | 55 | 29 | ||||||
| Oil Sands Mining | 15 | (38 | ) | (11 | ) | ||||
| Segment income (loss) | 15 | (53 | ) | (43 | ) | ||||
| Not allocated to segments | (207 | ) | (117 | ) | (706 | ) | |||
| Net income (loss) | \\$ | (192 | ) | \\$ | (170 | ) | \\$ | (749 | ) |
| Exploration expenses | |||||||||
| North America E&P | \\$ | 35 | \\$ | 37 | \\$ | 22 | |||
| International E&P | 10 | 4 | 10 | ||||||
| Oil Sands Mining | — | 7 | — | ||||||
| Segment exploration expenses | 45 | 48 | 32 | ||||||
| Not allocated to segments | 38 | 141 | 553 | ||||||
| Total | \\$ | 83 | \\$ | 189 | \\$ | 585 | |||
| Cash flows | |||||||||
| Net cash provided by operating activities | \\$ | 366 | \\$ | 178 | \\$ | 496 | |||
| Minus: changes in working capital | 78 | (112 | ) | 29 | |||||
| Net cash provided by operations before changes in working capital (a) | \\$ | 288 | \\$ | 290 | \\$ | 467 | |||
| Cash additions to property, plant and equipment | \\$ | (230 | ) | \\$ | (299 | ) | \\$ | (628 | ) |
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.
| Three Months Ended | Guidance(a) | |||||||
| Sept. 30 | June 30 | Sept. 30 | Q4 | Full Year | ||||
| (mboed) | 2016 | 2016 | 2015 | 2016 | 2016 | |||
| Net production available for sale | ||||||||
| North America E&P (b) | 216 | 224 | 263 | 205-215 | ||||
| International E&P excluding Libya (c) | 128 | 120 | 114 | 120-130 | ||||
| Combined North America & International E&P, excluding Libya (c) | 344 | 344 | 377 | 325-345 | 335-345 | |||
| Oil Sands Mining (d) | 58 | 40 | 57 | 40-45 | 45-50 | |||
| Total Company excluding Libya | 402 | 384 | 434 | |||||
| Libya | — | — | — | |||||
| Total Company | 402 | 384 | 434 | |||||
(a) Guidance includes the effect of acquisitions and divestitures closed to date.
(b) The Company closed on asset sales of certain fields within New Mexico and West Texas in July and August 2016. Certain Wyoming assets closed in June 2016. East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets closed in August 2015.
(c) Libya is excluded because of timing of future production and sales levels.
(d) Upgraded bitumen excluding blendstocks.
| Three Months Ended | ||||||
| Sept. 30 | June 30 | Sept. 30 | ||||
| (mboed) | 2016 | 2016 | 2015 | |||
| Net production available for sale | ||||||
| North America E&P | 216 | 224 | 263 | |||
| Less: Divestitures (a) | — | (14 | ) | (30 | ) | |
| Divestiture-adjusted North America E&P | 216 | 210 | 233 | |||
(a) Divestitures include the sale of certain New Mexico and West Texas assets in July and August 2016; Wyoming assets closed in June 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 | |||||
| Sept. 30 | June 30 | Sept. 30 | ||||
| 2016 | 2016 | 2015 | ||||
| North America E&P - net sales volumes | ||||||
| Liquid hydrocarbons (mbbld) | 164 | 173 | 205 | |||
| Bakken | 50 | 49 | 58 | |||
| Eagle Ford | 76 | 84 | 100 | |||
| Oklahoma resource basins | 22 | 14 | 10 | |||
| Other North America (a) | 16 | 26 | 37 | |||
| Crude oil and condensate (mbbld) | 122 | 135 | 166 | |||
| Bakken | 44 | 44 | 53 | |||
| Eagle Ford | 54 | 61 | 74 | |||
| Oklahoma resource basins | 11 | 6 | 4 | |||
| Other North America (a) | 13 | 24 | 35 | |||
| Natural gas liquids (mbbld) | 42 | 38 | 39 | |||
| Bakken | 6 | 5 | 5 | |||
| Eagle Ford | 22 | 23 | 26 | |||
| Oklahoma resource basins | 11 | 8 | 6 | |||
| Other North America (a) | 3 | 2 | 2 | |||
| Natural gas (mmcfd) | 315 | 310 | 338 | |||
| Bakken | 25 | 24 | 19 | |||
| Eagle Ford | 127 | 150 | 161 | |||
| Oklahoma resource basins | 116 | 82 | 76 | |||
| Other North America (a) | 47 | 54 | 82 | |||
| Total North America E&P (mboed) | 216 | 224 | 261 | |||
| International E&P - net sales volumes | ||||||
| Liquid hydrocarbons (mbbld) | 44 | 44 | 46 | |||
| Equatorial Guinea | 38 | 30 | 31 | |||
| United Kingdom | 6 | 14 | 15 | |||
| Crude oil and condensate (mbbld) | 32 | 33 | 35 | |||
| Equatorial Guinea | 26 | 19 | 21 | |||
| United Kingdom | 6 | 14 | 14 | |||
| Natural gas liquids (mbbld) | 12 | 11 | 11 | |||
| Equatorial Guinea | 12 | 11 | 10 | |||
| United Kingdom | — | — | 1 | |||
| Natural gas (mmcfd) | 489 | 457 | 441 | |||
| Equatorial Guinea | 462 | 430 | 418 | |||
| United Kingdom (b) | 27 | 27 | 23 | |||
| Total International E&P (mboed) | 126 | 120 | 119 | |||
| Oil Sands Mining - net sales volumes | ||||||
| Synthetic crude oil (mbbld) (c) | 65 | 49 | 65 | |||
| Total Company - net sales volumes (mboed) | 407 | 393 | 445 | |||
| Net sales volumes of equity method investees | ||||||
| LNG (mtd) | 6,620 | 5,797 | 5,700 | |||
| Methanol (mtd) | 1,529 | 1,303 | 1,125 | |||
| Condensate and LPG (boed) | 16,766 | 11,306 | 13,427 | |||
(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, and 8 mmcfd in the third and second quarter of 2016, and third quarter of 2015, respectively.
(c) Includes blendstocks.
| Supplemental Statistics (Unaudited) | Three Months Ended | ||||||||
| Sept. 30 | June 30 | Sept. 30 | |||||||
| 2016 | 2016 | 2015 | |||||||
| North America E&P - average price realizations (a) | |||||||||
| Liquid hydrocarbons (\\$ per bbl) | \\$ | 34.00 | \\$ | 35.07 | \\$ | 35.75 | |||
| Bakken | 37.33 | 38.38 | 37.41 | ||||||
| Eagle Ford | 32.81 | 34.31 | 34.87 | ||||||
| Oklahoma resource basins | 27.60 | 25.57 | 22.70 | ||||||
| Other North America (b) | 37.91 | 36.27 | 39.25 | ||||||
| Crude oil and condensate (\\$ per bbl) (c) | \\$ | 41.35 | \\$ | 40.77 | \\$ | 41.37 | |||
| Bakken | 41.25 | 42.00 | 40.18 | ||||||
| Eagle Ford | 41.67 | 41.21 | 42.74 | ||||||
| Oklahoma resource basins | 42.04 | 41.55 | 40.48 | ||||||
| Other North America (b) | 39.89 | 37.27 | 40.37 | ||||||
| Natural gas liquids (\\$ per bbl) | \\$ | 12.44 | \\$ | 14.84 | \\$ | 11.88 | |||
| Bakken | 10.63 | 7.73 | 5.07 | ||||||
| Eagle Ford | 11.45 | 15.68 | 12.15 | ||||||
| Oklahoma resource basins | 13.87 | 14.88 | 11.38 | ||||||
| Other North America (b) | 22.50 | 23.64 | 23.21 | ||||||
| Natural gas (\\$ per mcf) | \\$ | 2.67 | \\$ | 1.96 | \\$ | 2.75 | |||
| Bakken | 1.95 | 1.77 | 1.96 | ||||||
| Eagle Ford | 2.72 | 2.02 | 2.85 | ||||||
| Oklahoma resource basins | 2.74 | 1.92 | 2.82 | ||||||
| Other North America (b) | 2.73 | 1.95 | 2.70 | ||||||
| International E&P - average price realizations | |||||||||
| Liquid hydrocarbons (\\$ per bbl) | \\$ | 30.40 | \\$ | 32.11 | \\$ | 35.88 | |||
| Equatorial Guinea | 27.44 | 27.28 | 28.03 | ||||||
| United Kingdom | 48.01 | 42.32 | 52.36 | ||||||
| Crude oil and condensate (\\$ per bbl) | \\$ | 41.45 | \\$ | 42.21 | \\$ | 46.18 | |||
| Equatorial Guinea | 39.70 | 41.46 | 41.24 | ||||||
| United Kingdom | 49.82 | 43.25 | 53.48 | ||||||
| Natural gas liquids (\\$ per bbl) | \\$ | 1.93 | \\$ | 2.65 | \\$ | 2.69 | |||
| Equatorial Guinea (d) | 1.00 | 1.00 | 1.00 | ||||||
| United Kingdom | 26.36 | 25.99 | 28.81 | ||||||
| Natural gas (\\$ per mcf) | \\$ | 0.46 | \\$ | 0.53 | \\$ | 0.59 | |||
| Equatorial Guinea (d) | 0.24 | 0.24 | 0.24 | ||||||
| United Kingdom | 4.19 | 5.06 | 6.92 | ||||||
| Oil Sands Mining - average price realizations | |||||||||
| Synthetic crude oil (\\$ per bbl) | \\$ | 39.59 | \\$ | 40.88 | \\$ | 39.49 | |||
| Benchmark | |||||||||
| WTI crude oil (per bbl) | \\$ | 44.94 | \\$ | 45.64 | \\$ | 46.50 | |||
| Brent (Europe) crude oil (per bbl)(e) | \\$ | 45.79 | \\$ | 45.52 | \\$ | 50.23 | |||
| Henry Hub natural gas (per mmbtu)(f) | \\$ | 2.81 | \\$ | 1.95 | \\$ | 2.77 | |||
| WCS crude oil (per bbl)(g) | \\$ | 31.44 | \\$ | 32.29 | \\$ | 33.16 | |||
(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 \\$1.55, \\$0.12, and \\$1.87 for third and second quarters of 2016 and third quarter of 2015.
(d) 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.
(e) Average of monthly prices obtained from Energy Information Administration ("EIA") website.
(f) Settlement date average per mmbtu.
(g) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
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