HOUSTON, Nov. 01, 2017 (GLOBE NEWSWIRE) -- Marathon Oil Corporation (NYSE:MRO) today reported a third quarter 2017 net loss of $599 million, or $0.70 per diluted share, which 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 was $68 million, or $0.08 per diluted share. Net operating cash flow was $564 million, or $502 million before changes in working capital.
Highlights
- Total Company production excluding Libya averaged 371,000 net boed, up 6% sequentially and above top end of guidance; 23,000 net boed from Libya
- U.S. resource play production increased 12% sequentially, averaging 227,000 net boed; oil up 14% sequentially
- Eagle Ford production of 101,000 net boed up slightly, despite effects of Hurricane Harvey; continued strong results in Atascosa County
- Bakken production grew 20% sequentially to 59,000 net boed; five Hector wells achieved average 30-day rates of 2,380 boed (85% oil)
- Oklahoma Resource Basin production increased 18% sequentially to 58,000 net boed; STACK volatile oil wells continue to outperform expectations
- Northern Delaware production averaged 9,000 net boed; two Wolfcamp X-Y wells (both 4,600-foot laterals) achieved 30-day rates of 2,020 boed (67% oil) and 1,500 boed (69% oil); added fourth rig in October
- Expect full-year total Company production, excluding Libya, to be toward the high end of the revised 350,000 - 360,000 net boed range with a capital program, excluding lease and acquisition costs, of $2.1 billion
- Raised 2017 resource play exit rate guidance to 25 - 30 percent, up from 23 - 27 percent
- Anticipate full-year 2017 free cash flow neutrality, including dividends and working capital
"All year we've consistently executed across our portfolio delivering outstanding new well productivity, strong base performance, cost reductions and improved efficiencies," said Marathon Oil President and CEO Lee Tillman. "We continued this trend in the third quarter, exceeding the top end of our production guidance for both our U.S. and International E&P segments, while exercising capital discipline and achieving record low unit production costs in the U.S. Importantly, we now expect to end the year toward the high end of our full-year production guidance, while living within our means, including the dividend, at current strip pricing. This highlights the strength of our transformed portfolio and sets the stage for 2018 as we integrate the same discipline into our ongoing budget efforts."
U.S. E&P
U.S. E&P production available for sale averaged 245,000 net barrels of oil equivalent per day (boed) for third quarter 2017, above the top end of guidance. On a divestiture-adjusted basis, production was up 10 percent compared to the prior quarter and up 17 percent from the year-ago quarter. Third quarter unit production costs were $5.38 per barrel of oil equivalent (boe), 8 percent lower than the previous quarter and a record best for the Company since becoming an independent E&P in 2011.
EAGLE FORD: Marathon Oil's production in the Eagle Ford averaged 101,000 net boed in the third quarter, up from 100,000 net boed in the prior quarter, despite the effects of Hurricane Harvey. As planned, the Company brought 36 gross Company-operated wells to sales in the third quarter, compared to 41 wells to sales in the previous quarter. The testing of enhanced completion designs in Atascosa County continued to deliver encouraging results with the Guajillo South five-well pad averaging 30-day initial production (IP) rates of 1,920 boed (77% oil, 6,100-foot laterals).
BAKKEN: In third quarter 2017, Marathon Oil's Bakken production averaged 59,000 net boed, up 20 percent compared to 49,000 net boed in the prior quarter. The Company brought 20 gross Company-operated wells to sales in the third quarter, including eight in West Myrmidon, seven in East Myrmidon and five in Hector, all of which demonstrated strong early results. Enhanced completion design trials in the Company's 115,000-acre Hector area continued to exceed expectations with average 30-day IP rates from the five Hector wells of 2,380 boed (85% oil). This includes the Clarice Middle Bakken well in the Hector area that set an industry record for the best 30-day oil rate in the Williston Basin with 2,785 barrels of oil per day (3,285 boed, 85% oil).
OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production increased 18 percent to 58,000 net boed during third quarter 2017, compared to 49,000 net boed in the prior quarter and up more than 40 percent from the year-ago quarter. The Company brought 15 gross Company-operated wells to sales during the quarter predominately focused on leasehold capture and delineation activity. The Landreth, a STACK Meramec leasehold well in the volatile oil window in Blaine County, had an average 30-day IP rate of 2,420 boed (59% oil, 4,600-foot lateral), and an early test of the Osage in Kingfisher County achieved promising results with a 30-day IP of 850 boed (55% oil, 4,700-foot lateral).
NORTHERN DELAWARE: The Company's Northern Delaware production averaged 9,000 net boed in third quarter 2017, reflecting a full quarter of production and five wells to sales in Eddy and Lea Counties. The Chicken Fry and El Presidente, both Wolfcamp X-Y wells in southwest Eddy County, achieved 2,020 boed (67% oil, 4,600-foot lateral) and 1,500 boed (69% oil, 4,600-foot lateral), respectively. The Company transitioned to a dedicated completions crew at the end of the third quarter, and added a fourth rig in October.
International E&P
International E&P production available for sale (excluding Libya) averaged 126,000 net boed for third quarter 2017, above the top end of guidance. This compares to 127,000 net boed in the prior quarter, and 128,000 net boed in the year-ago quarter. Third quarter 2017 unit production costs (excluding Libya) were $5.18 per boe. Equatorial Guinea production available for sale averaged 112,000 net boed in third quarter 2017, up from 107,000 net boed in the previous quarter, primarily due to facilities and well optimization. U.K. production available for sale averaged 12,000 net boed in third quarter 2017, compared to 18,000 net boed in the previous quarter, reflecting the beginning of planned turn-around activity at Brae and Foinaven. Marathon Oil had four liftings in Libya, with production available for sale averaging 23,000 net boed in the third quarter.
Guidance
Marathon Oil expects fourth quarter 2017 U.S. E&P production available for sale to average 255,000 to 265,000 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 including the completion of planned turnaround activity at Brae and Foinaven.
The Company expects full-year total Company production available for sale, excluding Libya, to end the year toward the top end of guidance and has narrowed its forecast, resulting in a new range of 350,000 to 360,000 net boed. U.S. resource play exit rate production guidance for both oil and BOE is now expected to be 25 to 30 percent higher than fourth quarter 2016, up slightly from the prior guidance range. Marathon Oil expects its 2017 capital program, excluding lease and acquisition costs, to be approximately $2.1 billion, at the low end of the guidance range.
Corporate
Net cash provided by operating activities from continuing operations was $564 million during third quarter 2017, and net cash provided by continuing operations before changes in working capital was $502 million. Cash additions to property, plant and equipment (PP&E) were $530 million in third quarter 2017.
Total liquidity as of Sept. 30 was $5.2 billion, which consists of $1.8 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion. Approximately $750 million in remaining proceeds from the sale of the Company's Canadian subsidiary are scheduled to be received in first quarter 2018.
For the remainder of 2017, Marathon Oil's open hedge positions included 70,000 barrels per day (bpd) of oil at a weighted average floor price of $53.82, hedged through a combination of three-way collars and fixed price swaps, as of Sept. 30. Additionally, in 2018 the Company had hedged 68,500 bpd of oil at a weighted average floor price of $50.95 through three-way collars, as of Sept. 30.
The adjustments to net loss from continuing operations for third quarter 2017 totaled $491 million before tax, and include $451 million primarily consisting of non-cash impairment charges on proved and unproved properties as a result of the anticipated sale of the Company's non-operated working interests in certain non-core international assets and due to lower forecasted long-term commodity prices. Also included in these adjustments are a gain on termination of interest rate swaps of $47 million, offset by a loss on early extinguishment of debt of $46 million and an unrealized loss on commodity derivatives of $56 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 following this release today, Nov. 1. The Company will conduct a question and answer webcast/call on Thursday, Nov. 2, 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. 3.
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, asset quality, drilling plans, production guidance, capital plans, cash flows, future payments for the Canadian disposition, and other plans and objectives for future operations, are forward-looking statements. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," "may," "plan," "project," "seek," "should," "target," "will," "would," or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While 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; the inability for any party to satisfy closing conditions with respect to the Canadian subsidiary disposition; drilling and operating risks; well production timing; availability of drilling rigs, materials and labor, including associated costs; 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 2016 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.
A photo accompanying this announcement is available at http://www.globenewswire.com/NewsRoom/AttachmentNg/ba379186-10c7-48e7-b0be-336ea3d94a93
Media Relations Contact:
Lee Warren: 713-296-4103
Investor Relations Contact:
Zach Dailey: 713-296-4140
| Consolidated Statements of Income (Unaudited) | Three Months Ended | ||||||||
| Sept. 30 | June 30 | Sept. 30 | |||||||
| (In millions, except per share data) | 2017 | 2017 | 2016 | ||||||
| Revenues and other income: | |||||||||
| Sales and other operating revenues, including related party | $ | 1,114 | $ | 958 | $ | 781 | |||
| Marketing revenues | 48 | 35 | 80 | ||||||
| Income from equity method investments | 63 | 51 | 59 | ||||||
| Net gain (loss) on disposal of assets | 19 | 6 | 47 | ||||||
| Other income | 8 | 9 | 23 | ||||||
| Total revenues and other income | 1,252 | 1,059 | 990 | ||||||
| Costs and expenses: | |||||||||
| Production | 194 | 176 | 160 | ||||||
| Marketing, including purchases from related parties | 49 | 38 | 80 | ||||||
| Other operating | 109 | 111 | 183 | ||||||
| Exploration | 294 | 30 | 83 | ||||||
| Depreciation, depletion and amortization | 641 | 592 | 522 | ||||||
| Impairments | 201 | — | 47 | ||||||
| Taxes other than income | 44 | 45 | 35 | ||||||
| General and administrative | 97 | 93 | 104 | ||||||
| Total costs and expenses | 1,629 | 1,085 | 1,214 | ||||||
| Income (loss) from operations | (377 | ) | (26 | ) | (224 | ) | |||
| Net interest and other | (35 | ) | (86 | ) | (89 | ) | |||
| Loss on early extinguishment of debt | (46 | ) | — | — | |||||
| Income (loss) from continuing operations before income taxes | (458 | ) | (112 | ) | (313 | ) | |||
| Provision (Benefit) for income taxes | 141 | 41 | (107 | ) | |||||
| Income (loss) from continuing operations | (599 | ) | (153 | ) | (206 | ) | |||
| Discontinued operations (a) | — | 14 | 14 | ||||||
| Net income (loss) | $ | (599 | ) | $ | (139 | ) | $ | (192 | ) |
| Adjustments for special items from continuing operations (pre-tax): | |||||||||
| Net (gain) loss on dispositions | (19 | ) | (6 | ) | (38 | ) | |||
| Proved property impairments | 201 | — | 47 | ||||||
| Exploratory dry well costs, unproved property impairments and other | 250 | — | — | ||||||
| Pension settlement | 8 | 3 | 14 | ||||||
| Unrealized (gain) loss on derivative instruments | 56 | (43 | ) | (25 | ) | ||||
| Gain on termination of interest rate swaps | (47 | ) | — | — | |||||
| Loss on extinguishment of debt | 46 | — | — | ||||||
| Rig termination payment | — | — | 113 | ||||||
| Other | (4 | ) | (3 | ) | 37 | ||||
| Provision (benefit) for income taxes related to special items from continuing operations | 40 | — | (53 | ) | |||||
| Adjustments for special items from continuing operations: | $ | 531 | $ | (49 | ) | $ | 95 | ||
| Adjusted net income (loss) from continuing operations (b) | $ | (68 | ) | $ | (202 | ) | $ | (111 | ) |
| Adjustments for special items from discontinued operations (pre-tax): | |||||||||
| Net (gain) loss on disposition (a) | — | 43 | — | ||||||
| Provision (benefit) for income taxes related to special items from discontinued operations (a) | — | — | — | ||||||
| Adjusted net income (loss) (b) | $ | (68 | ) | $ | (145 | ) | $ | (97 | ) |
| Per diluted share: | |||||||||
| Income (loss) from continuing operations | $ | (0.70 | ) | $ | (0.18 | ) | $ | (0.24 | ) |
| Net Income (loss) | $ | (0.70 | ) | $ | (0.16 | ) | $ | (0.23 | ) |
| Adjusted net income (loss) from continuing operations (b) | $ | (0.08 | ) | $ | (0.24 | ) | $ | (0.13 | ) |
| Adjusted net income (loss) (b) | $ | (0.08 | ) | $ | (0.17 | ) | $ | (0.11 | ) |
| Weighted average diluted shares | 850 | 850 | 847 | ||||||
(a) The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017. The Canadian oil sands business is reflected as discontinued operations in all periods presented. The discontinued operations presentation has not yet been audited; therefore, reported values are preliminary.
(b) 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) | 2017 | 2017 | 2016 | ||||||
| Segment income (loss) | |||||||||
| United States E&P | $ | (38 | ) | $ | (107 | ) | $ | (59 | ) |
| International E&P | 104 | 59 | 59 | ||||||
| Segment income (loss) | 66 | (48 | ) | — | |||||
| Not allocated to segments | (665 | ) | (105 | ) | (206 | ) | |||
| Loss from continuing operations | (599 | ) | (153 | ) | (206 | ) | |||
| Discontinued operations (a) | — | 14 | 14 | ||||||
| Net income (loss) | $ | (599 | ) | $ | (139 | ) | $ | (192 | ) |
| Exploration expenses | |||||||||
| United States E&P | $ | 41 | $ | 30 | $ | 35 | |||
| International E&P | 3 | — | 10 | ||||||
| Segment exploration expenses | 44 | 30 | 45 | ||||||
| Not allocated to segments | 250 | — | 38 | ||||||
| Total | $ | 294 | $ | 30 | $ | 83 | |||
| Cash flows | |||||||||
| Net cash provided by operating activities from continuing operations | $ | 564 | $ | 422 | $ | 259 | |||
| Minus: changes in working capital | 62 | (49 | ) | 72 | |||||
| Total net cash provided from continuing operations before changes in working capital (b) | $ | 502 | $ | 471 | $ | 187 | |||
| Net cash provided by operating activities from discontinued operations (a) | — | 46 | 108 | ||||||
| Cash additions to property, plant and equipment | $ | (530 | ) | $ | (492 | ) | $ | (221 | ) |
(a) The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017. The Canadian oil sands business is reflected as discontinued operations in all periods presented. The discontinued operations presentation has not yet been audited; therefore, reported values are preliminary.
(b) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.
| Three Months Ended | Guidance(a) | |||||||
| Sept. 30 | June 30 | Sept. 30 | Fourth Quarter | Full Year | ||||
| (mboed) | 2017 | 2017 | 2016 | 2017 | 2017 | |||
| Net production available for sale | ||||||||
| United States E&P (a) | 245 | 222 | 216 | 255-265 | ||||
| International E&P excluding Libya (b) | 126 | 127 | 128 | 120-130 | ||||
| Total continuing operations, excluding Libya (b) | 371 | 349 | 344 | 350-360 | ||||
| Libya | 23 | 11 | — | |||||
| Total continuing operations | 394 | 360 | 344 | |||||
(a) The Company closed on sales of certain Oklahoma conventional assets in September 2017, certain Wyoming assets in June and November 2016, and certain fields within New Mexico and West Texas in July, August, and October 2016.
(b) Libya is excluded because of the timing of future production and sales levels.
| Three Months Ended | ||||||
| Sept. 30 | June 30 | Sept. 30 | ||||
| (mboed) | 2017 | 2017 | 2016 | |||
| Net production available for sale | ||||||
| United States E&P | 245 | 222 | 216 | |||
| Less: Divestitures (a) | (2 | ) | (2 | ) | (9 | ) |
| Divestiture-adjusted United States E&P | 243 | 220 | 207 | |||
| Divestiture-adjusted total continuing operations | 392 | 358 | 335 | |||
| Discontinued operations (b) | — | 29 | 58 | |||
(a) Divestitures include the sale of certain Oklahoma conventional assets closed in September 2017, certain Wyoming assets closed in June and November 2016, and certain New Mexico and West Texas assets closed in July, August, and October 2016. These production volumes have been removed from all periods shown in arriving at divestiture-adjusted United States E&P net production available for sale.
(b) The Company closed on its sale of the Canadian oil sands business on May 31, 2017. The Canadian oil sands business is reflected as discontinued operations in all periods presented. The discontinued operations presentation has not yet been audited; therefore, reported values are preliminary.
| Supplemental Statistics (Unaudited) | Three Months Ended | |||||
| Sept. 30 | June 30 | Sept. 30 | ||||
| 2017 | 2017 | 2016 | ||||
| United States E&P - net sales volumes | ||||||
| Liquid hydrocarbons (mbbld) | 183 | 165 | 164 | |||
| Oklahoma resource basins | 31 | 26 | 22 | |||
| Eagle Ford | 80 | 79 | 76 | |||
| Bakken | 55 | 45 | 50 | |||
| Northern Delaware | 6 | 3 | — | |||
| Other United States (a) | 11 | 12 | 16 | |||
| Crude oil and condensate (mbbld) | 139 | 125 | 122 | |||
| Oklahoma resource basins | 17 | 14 | 11 | |||
| Eagle Ford | 58 | 59 | 54 | |||
| Bakken | 49 | 39 | 44 | |||
| Northern Delaware | 6 | 2 | — | |||
| Other United States (a) | 9 | 11 | 13 | |||
| Natural gas liquids (mbbld) | 44 | 40 | 42 | |||
| Oklahoma resource basins | 14 | 12 | 11 | |||
| Eagle Ford | 22 | 20 | 22 | |||
| Bakken | 6 | 6 | 6 | |||
| Northern Delaware | — | 1 | — | |||
| Other United States (a) | 2 | 1 | 3 | |||
| Natural gas (mmcfd) | 369 | 341 | 315 | |||
| Oklahoma resource basins | 161 | 138 | 116 | |||
| Eagle Ford | 126 | 127 | 127 | |||
| Bakken | 26 | 25 | 25 | |||
| Northern Delaware | 15 | 7 | — | |||
| Other United States (a) | 41 | 44 | 47 | |||
| Total United States E&P (mboed) | 244 | 222 | 216 | |||
| International E&P - net sales volumes | ||||||
| Liquid hydrocarbons (mbbld) | 81 | 55 | 44 | |||
| Equatorial Guinea | 39 | 30 | 38 | |||
| Libya | 23 | 11 | — | |||
| United Kingdom | 16 | 13 | 6 | |||
| Other International | 3 | 1 | — | |||
| Crude oil and condensate (mbbld) | 68 | 43 | 32 | |||
| Equatorial Guinea | 27 | 18 | 26 | |||
| Libya | 23 | 11 | — | |||
| United Kingdom | 15 | 13 | 6 | |||
| Other International | 3 | 1 | — | |||
| Natural gas liquids (mbbld) | 13 | 12 | 12 | |||
| Equatorial Guinea | 12 | 12 | 12 | |||
| United Kingdom | 1 | — | — | |||
| Natural gas (mmcfd) | 507 | 478 | 489 | |||
| Equatorial Guinea | 482 | 452 | 462 | |||
| United Kingdom (b) | 25 | 26 | 27 | |||
| Total International E&P (mboed) | 165 | 135 | 126 | |||
| Total Company continuing operations - net sales volumes (mboed) | 409 | 357 | 342 | |||
| Net sales volumes of equity method investees | ||||||
| LNG (mtd) | 6,943 | 6,243 | 6,620 | |||
| Methanol (mtd) | 1,366 | 1,182 | 1,529 | |||
| Condensate and LPG (boed) | 17,216 | 11,608 | 16,766 | |||
(a) Includes Oklahoma, Wyoming, New Mexico, and other conventional onshore U.S. production. The sale of certain Oklahoma assets closed in September 2017, certain Wyoming assets closed in June and November 2016, and certain New Mexico and West Texas assets closed in July, August, and October 2016.
(b) Includes natural gas acquired for injection and subsequent resale.
| Supplemental Statistics (Unaudited) | Three Months Ended | ||||||||
| Sept. 30 | June 30 | Sept. 30 | |||||||
| 2017 | 2017 | 2016 | |||||||
| United States E&P - average price realizations (a) | |||||||||
| Liquid hydrocarbons ($ per bbl) | $ | 40.48 | $ | 39.00 | $ | 34.00 | |||
| Oklahoma resource basins | 35.84 | 33.78 | 27.60 | ||||||
| Eagle Ford | 39.87 | 38.35 | 32.81 | ||||||
| Bakken | 43.09 | 42.22 | 37.33 | ||||||
| Northern Delaware | 44.00 | 37.58 | — | ||||||
| Other United States (b) | 43.23 | 42.72 | 37.91 | ||||||
| Crude oil and condensate ($ per bbl) (c) | $ | 46.65 | $ | 45.81 | $ | 41.35 | |||
| Oklahoma resource basins | 46.39 | 45.42 | 42.04 | ||||||
| Eagle Ford | 47.56 | 45.75 | 41.67 | ||||||
| Bakken | 46.06 | 46.20 | 41.25 | ||||||
| Northern Delaware | 44.49 | 43.38 | — | ||||||
| Other United States (b) | 45.83 | 45.71 | 39.89 | ||||||
| Natural gas liquids ($ per bbl) | $ | 20.86 | $ | 17.61 | $ | 12.44 | |||
| Oklahoma resource basins | 23.58 | 19.63 | 13.87 | ||||||
| Eagle Ford | 19.52 | 16.63 | 11.45 | ||||||
| Bakken | 17.89 | 15.16 | 10.63 | ||||||
| Northern Delaware | 30.23 | 17.54 | — | ||||||
| Other United States (b) | 24.94 | 23.78 | 22.50 | ||||||
| Natural gas ($ per mcf) (d) | $ | 2.71 | $ | 3.05 | $ | 2.67 | |||
| Oklahoma resource basins | 2.69 | 3.07 | 2.74 | ||||||
| Eagle Ford | 2.83 | 3.06 | 2.72 | ||||||
| Bakken | 2.08 | 3.14 | 1.95 | ||||||
| Northern Delaware | 3.00 | 2.72 | — | ||||||
| Other United States (b) | 2.67 | 2.92 | 2.73 | ||||||
| International E&P - average price realizations | |||||||||
| Liquid hydrocarbons ($ per bbl) | $ | 43.69 | $ | 37.11 | $ | 30.40 | |||
| Equatorial Guinea | 32.78 | 24.30 | 27.44 | ||||||
| Libya | 56.93 | 50.94 | — | ||||||
| United Kingdom | 51.12 | 53.66 | 48.01 | ||||||
| Other International | 40.67 | 40.64 | — | ||||||
| Crude oil and condensate ($ per bbl) | $ | 51.23 | $ | 47.04 | $ | 41.45 | |||
| Equatorial Guinea | 46.91 | 39.73 | 39.70 | ||||||
| Libya | 56.93 | 50.94 | — | ||||||
| United Kingdom | 51.72 | 54.15 | 49.82 | ||||||
| Other International | 40.67 | 40.64 | — | ||||||
| Natural gas liquids ($ per bbl) | $ | 2.25 | $ | 1.77 | $ | 1.93 | |||
| Equatorial Guinea (e) | 1.00 | 1.00 | 1.00 | ||||||
| United Kingdom | 32.58 | 32.33 | 26.36 | ||||||
| Natural gas ($ per mcf) | $ | 0.51 | $ | 0.57 | $ | 0.46 | |||
| Equatorial Guinea (e) | 0.24 | 0.24 | 0.24 | ||||||
| United Kingdom | 5.71 | 6.27 | 4.19 | ||||||
| Benchmark | |||||||||
| WTI crude oil (per bbl) | $ | 48.20 | $ | 48.15 | $ | 44.94 | |||
| Brent (Europe) crude oil (per bbl)(f) | $ | 52.11 | $ | 49.67 | $ | 45.79 | |||
| Henry Hub natural gas (per mmbtu)(g) | $ | 3.00 | $ | 3.18 | $ | 2.81 | |||
(a) Excludes gains or losses on derivative instruments.
(b) Includes Oklahoma, Wyoming, New Mexico, and other conventional onshore U.S. production. The sale of certain Oklahoma assets closed in September 2017, certain Wyoming assets closed in June and November 2016, and certain New Mexico and West Texas assets closed in July, August, and October 2016.
(c) Inclusion of realized gains on crude oil derivative instruments would have increased liquid hydrocarbons average price realizations by $2.42, $1.07, and $1.55, for the third and second quarter of 2017, and third quarter of 2016, respectively.
(d) Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal 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.
| Crude Oil | ||||||||||||||
| 2017 | 2018 | |||||||||||||
| Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||
| Three-Way Collars (a) | ||||||||||||||
| Volume (Bbls/day) | 50,000 | 75,000 | 75,000 | 62,000 | 62,000 | |||||||||
| Weighted average price per Bbl: | ||||||||||||||
| Ceiling | $ | 60.37 | $ | 56.24 | $ | 56.24 | $ | 56.08 | $ | 56.08 | ||||
| Floor | $ | 54.80 | $ | 51.33 | $ | 51.33 | $ | 50.50 | $ | 50.50 | ||||
| Sold put | $ | 47.80 | $ | 44.73 | $ | 44.73 | $ | 43.61 | $ | 43.61 | ||||
| Swaps (b)(c) | ||||||||||||||
| Volume (Bbls/day) | 20,000 | — | — | — | — | |||||||||
| Weighted average price per Bbl | $ | 51.37 | — | — | — | — | ||||||||
| Sold call options (d) | ||||||||||||||
| Volume (Bbls/day) | 35,000 | — | — | — | — | |||||||||
| Weighted average price per Bbl | $ | 61.91 | — | — | — | — | ||||||||
| Basis Swaps (e) | ||||||||||||||
| Volume (Bbls/day) | — | 5,000 | 5,000 | 10,000 | 10,000 | |||||||||
| Weighted average price per Bbl | — | $ | (0.60 | ) | $ | (0.60 | ) | $ | (0.67 | ) | $ | (0.67 | ) | |
(a) Between Sept. 30, 2017 and Oct. 30, 2017, Marathon Oil entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $58.07, a floor price of $53.70, and a sold put price of $47.00.
(b) The counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $52.67 per Bbl indexed to NYMEX WTI, which is exercisable on Dec. 29, 2017. If the counterparties exercise, the term of the fixed-price swaps would be from January - June 2018 and, if all such options are exercised, for 10,000 Bbls/day.
(c) Between Sept. 30, 2017 and Oct. 30, 2017, we entered into 40,000 Bbls/day of fixed-price swaps for November - December 2017 with a weighted average price of $54.11.
(d) Call options settle monthly.
(e) The basis differential price is between WTI Midland and WTI Cushing.
| Natural Gas | ||||||||||
| 2017 | 2018 | |||||||||
| Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||
| Three-Way Collars | ||||||||||
| Volume (MMBtu/day) | 120,000 | 200,000 | 160,000 | 160,000 | 160,000 | |||||
| Weighted average price per MMBtu: | ||||||||||
| Ceiling | $ | 3.71 | $ | 3.79 | $ | 3.61 | $ | 3.61 | $ | 3.61 |
| Floor | $ | 3.14 | $ | 3.08 | $ | 3.00 | $ | 3.00 | $ | 3.00 |
| Sold put | $ | 2.60 | $ | 2.55 | $ | 2.50 | $ | 2.50 | $ | 2.50 |
| Swaps | ||||||||||
| Volume (MMBtu/day) | 20,000 | — | — | — | — | |||||
| Weighted average price per MMBtu | $ | 2.93 | — | — | — | — | ||||